North America to Drown in Oil as Mexico Ends Monopoly

North America to Drown in Oil as Mexico Ends Monopoly

By Joe Carroll and Bradley Olson  Dec 16, 2013 12:54 PM ET  

Photographer: Susana Gonzalez/Bloomberg

The Petroleos Mexicanos (Pemex) La Muralla IV deep sea crude oil platform in the waters… Read More

The flood of North American crude oil is set to become a deluge asMexico dismantles a 75-year-old barrier to foreign investment in its oil fields.

Plagued by almost a decade of slumping output that has degraded Mexico’s take from a $100-a-barrel oil market, President Enrique Pena Nieto is seeking an end to the state monopoly over one of the biggest crude resources in the Western Hemisphere. The doubling in Mexican oil output that Citigroup Inc. said may result from inviting international explorers to drill would be equivalent to adding another Nigeria to world supply, or about 2.5 million barrels a day.

That boom would augment a supply surge from U.S. and Canadian wells that Exxon Mobil Corp. (XOM) predicts will vault North American production ahead of every OPEC member except Saudi Arabia within two years. With U.S. refineries already choking on more oil than they can process, producers from Exxon to ConocoPhillips are clamoring for repeal of the export restrictions that have outlawed most overseas sales of American crude for four decades.

“This is going to be a huge opportunity for any kind of player” in the energy sector, said Pablo Medina, a Latin American upstream analyst at Wood Mackenzie Ltd. in Houston. “All the companies are going to have to turn their heads and start analyzing Mexico.”

Unprecedented Output

An influx of Mexican oil would contribute to a glut that is expected to lower the price of Brent crude, the benchmark for more than half the world’s crude that has averaged $108.62 a barrel this year, to as low as $88 a barrel in 2017, based on estimates from analysts in a Bloomberg survey. Five of the seven analysts who provided 2017 forecasts said prices would be lower than this year.

The revolution in shale drilling that boosted U.S. oil output to a 25-year high this month will allow North America to join the ranks of the world’s crude-exporting continents by 2040, Exxon said in its annual global energy forecast on Dec. 12. Europe and the Asia-Pacific region will be the sole crude import markets by that date, the Irving, Texas-based energy producer said.

Related: Oil Supply Surge Brings Calls to Ease U.S. Export Ban

Exxon’s forecast, compiled annually by a team of company economists, scientists and engineers, didn’t take into account any changes in Mexico, William Colton, the company’s vice president of strategic planning, said during a presentation at the Center for Strategic and International Studies in Washington on Dec. 12.

Opening Mexico’s oilfields to foreign investment would be “a win-win if ever there was one,” said Colton, who described the move as “very good for the people of Mexico and people everywhere in the world who use energy.”

$15 Billion Boost

Mexico Invites Foreigners to Boost Drilling

The bill ending the state monopoly was approved by the Mexican Congress Dec. 12. Before becoming law, the proposal must be ratified by state assemblies, most of which are controlled by proponents of the reform. Oil companies will be offered production-sharing contracts, or licenses where they get ownership of the pumped oil and authority to book crude reserves for accounting purposes. The contracts will be overseen by government regulators.

Though some foreign companies already operate in Mexico under service contracts with Petroleos Mexicanos, or Pemex, the reform could increase foreign investment by as much as $15 billion annually and boost potential economic growth by half a percentage point, JPMorgan Chase & Co. said in a Nov. 28 report.

Potential Delays

A doubling in production as suggested by Citigroup’s Ed Morsewould put Mexican output at 5 million barrels a day, an unprecedented level for Pemex, the state oil company created during nationalization in 1938.

U.S. crude production will expand to 9.5 million barrels a day in 2016, the highest since the nation’s peak in 1970, the U.S. Energy Information Administration said today. That contrasts with last year’s EIA forecast that production would reach 7.5 million in 2019 before gradually declining to 6.1 million in 2040. U.S. output reached an all-time high 9.6 million in 1970.

A doubling of Mexico’s output maybe be slower to realize than the most bullish predictions as companies confront barriers in accessing capital and human resources needed for development, Riccardo Bertocco, a partner at Bain & Co. in Dallas.

An increase of 1 million barrels a day in output is the most realistic upper limit of what Mexico could achieve by 2025 based on the cost for new infrastructure, competition for new fields and opportunities all over the U.S., Bertocco said in a telephone interview Dec. 12.

“The opportunities are there, but they are still far from being materialized,” he said.

Regulator Inexperience

Drilling in Mexico will be held back by a lack of infrastructure, such as pipelines, in some of the potential shale developments. The government will need to decide on details for development such as tax rates, royalty structures and standards for booking reserves, Kurt Hallead, an analyst at RBC Capital Markets, wrote in a Dec. 12 note to clients.

It will take time to organize and conduct bidding rounds for licenses, and additional exploration, such as seismic tests, will need to be done, Hallead said.

“We are not expecting any significant impact from the reform to be felt in the next two years,” he wrote.

Foreign oil companies will face a backlash from Mexicans opposed to sharing the nation’s oil wealth, said Ricardo Monreal Avila of Movimiento Ciudadano Party, who sees the reform as violating Mexico’s constitution.

Local Opposition

“We are going to see serious problems in the operations of these reforms. Indigenous communities and places chosen by foreign companies for extraction will not allow them on their property. There are going to be serious operational problems.”

Brent crude futures, the benchmark for more than half the world’s oil, rose as much as 1.8 percent to $110.80 a barrel in Londontoday, the biggest intraday gain in two weeks, after Libyan rebels refused to relinquish control over oil ports to the central government.Libya, home to Africa’s largest proven reserves, has seen output tumble to the lowest since 2011 amid civil strife.

The first assets that will attract foreign investment will be mature oil fields drilled decades ago and reservoirs that need injections of steam or carbon dioxide to coax more crude out of the ground, Medina said. Deep-water prospects, shale and other technically challenging endeavors will follow later, he said.

The level of investor interest will be partly determined by which assets Pemex chooses to keep and which it will put up for auction, Medina said.

Chicontepec Price

The Chicontepec field northeast of Mexico City may be among the richest prizes Pemex surrenders after its problems overcoming low pressure and disconnected crude deposits that have limited output, Medina said. Production that has averaged about 60,000 barrels a day may be increased to more than 100,000 by an international producer experienced in handling such fields, he said.

Chicontepec is just one of the over-budget, long-delayed projects for which Pemex will be eager to find partners, said Jose Antonio Prado, a former general counsel of Mexico’s energy ministry and Pemex official.

“The Mexican state will be able to incorporate private participants in projects that are already in force as well as new opportunities,” said Prado, now a partner at the law firm Holland & Knight LLP in Mexico City.

Deep Water

The reforms are especially important to open up exploration in Mexico’s deep-water fields, where additional capital, as well as better technology and expertise are needed, Carlos Solé, a Houston-based partner at Baker Botts LLP, said in a telephone interview. Pemex estimated the country’s deep-water Gulf of Mexico prospects may hold the equivalent of 26.6 billion barrels of crude.

Onshore, the potential is even greater with more than 60 billion untapped barrels, according to a Pemex presentation last month.

Some of the potential shale production sits across the border fromTexas’s prolific Eagle Ford formation. The most resource-rich area studied so far is around the city of Tampico, a coastal city about 300 miles (480 kilometers) south of the bottom tip of the Texas border.

“I can’t tell you the amount of banks and investment funds coming from the U.S. and Europe that have been talking to us and are trying to have an expectation of what’s going to happen with the energy reform,” Prado said. “All those guys are going to be in Mexico next year in various forms trying to seek new opportunities.”

To contact the reporters on this story: Joe Carroll in Chicago atjcarroll8@bloomberg.net; Bradley Olson in Houston atbradleyolson@bloomberg.net

To contact the editor responsible for this story: Susan Warren atsusanwarren@bloomberg.net

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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.

Investing in natural gas

29 August 2013

Investing in natural gas

By Bryan Borzykowski
Is it a good idea to invest in natural gas?(Thinkstock)

British Columbia is best known for its beautiful mountain views and world-class skiing, but by 2015 it could be famous for something else: natural gas transportation.

That may not sound as exciting as a night out in Whistler, but if the Canadian province can successfully build North America’s first major liquefied natural gas terminal, it could dramatically alter the energy industry. With many people’s money tied up in energy stocks, it could boost the average investor’s returns too.

While other LNG terminals in places like Malaysia, Qatar, Yemen, Australia and Norway already send gas to Europe and Asia, it is cheap, abundant North American gas, that many utilities and gas companies are waiting to get their hands on. Demand for the commodity is highest in Asia.

One reason why people are excited about North American gas is that many gas-using companies want to buy from a locale that doesn’t face political risks, said Maartin Bloemen, a Toronto-based portfolio manager with Templeton Global Equity Group. European companies import a lot of gas from Russia, while Japanese and Chinese businesses buy from the Middle East.

Currently, natural gas sells for about $3.50 per 1,000 cubic feet in North America; it goes for $9 in Europe, and about $16 in the growing Asian market. Many investment experts think that once China, Japan and other markets get a hold of North America’s abundant supply of gas, the price gap between North American and Asian gas could close, said Ted Davis, portfolio manager at Denver-based Fidelity Investments.

A more global gas market could give people’s investment portfolios a boost. — Andrea Williams

A more global market could give people’s investment portfolios a boost, said Andrea Williams, a London-based portfolio manager with Royal London Asset Management. Since 2008, investors around the world have suffered from falling North American natural gas prices. The price of gas plummeted by about 85% over the last five years and that has impacted the earnings and stock prices of the many energy operations exposed to the region.

If North American gas prices rise, so too should the fortunes of the continent’s companies, said Davis. Conversely, if gas prices fall overseas — it’s likely they’ll drop somewhat after North American supply hits Asian shores, said Williams — the Russian, Middle Eastern and Australian companies that supply Europe and Asia now could be in trouble, she said.

Getting excited

While the first North American gas plants are still a couple of years away from being built, investors are already getting excited about North American investment opportunities, said Davis.

According to the US Energy Information Administration, North America produces the most natural gas out of any region in the world. With such rich resources, many companies will be able to grow production for decades, said Davis. Right now, all that production is a problem — there’s not enough domestic demand to reduce supply — but investors are anticipating that once gas goes offshore, that imbalance will be fixed.

Historically, European and emerging market producers traded at a premium to North American companies, but that’s starting to change. For example, Russian energy companies have traded at an average 24% premium over the past decade, but now trade at a 70% discount, said Davis. Major European energy companies have traded at a 26% premium over the last 10 years, but now trade at a 27% discount.

Despite the rising valuations, Davis still thinks that North America companies are the better bets in this changing energy environment.

Best bets?

The best bets are the mega-cap energy players, such as Chevron, Royal Dutch Shell and ExxonMobil, said both Williams and Bloemen. Many already have a stake in LNG terminals being built in North America. They are also buying stakes in terminals in Australia, which will help get gas off that continent, too.  In addition, these heavyweight companies have a leg up on signing long-term contracts with utility companies.

“You want someone who already has projects on the go,” Bloemen said. “Newer projects are way behind the eight ball and you want to own a company that can scale up easily.”

Williams is partial to integrated producers — companies that sell gas, but also produce and refine oil as well. These operations are more diversified and should therefore be better able to withstand short-term volatility in the sector than a pure gas producer, she said.

While Davis is keen on the bigger players too, he also suggests looking at small North American exploration and production companies, such as EOG Resources and Apache Corp, which have been much more successful at finding resources than their European and Asian peers.

These operations aren’t necessarily involved in transporting gas overseas, but they are assisting other nations, such as China, Latin America and the U.K., tap into their own gas fields.

“These are the companies that took the risk and unlocked these resources over time,” said Davis. “Their technology will be applied elsewhere in the world.”

Energy experts say there’s no question that global demand for natural gas is increasing and that the industry will forever change once natural gas gets shipped from North America to Asia. While it’s likely big global companies that will benefit first, nearly all investors with exposure to the energy sector should see some bump in their portfolio starting in 2015, said Williams.

“We’re happy to invest in this sector,” she said. “As emerging markets become more westernised, the need for gas will just go up.”

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Japan’s entire nuclear power fleet is offline

THE WALL STREET JOURNAL Energy Journal
Japanese Nuclear Plants Power Down 

    By Ben Winkley

 

JAPAN POWERS DOWN

Japan’s entire nuclear power fleet is offline, two-and-a-half years after the Fukushima Daiichi reactor accident.

Only two of Japan’s 50 reactors have generated electricity since July 2012. On Sunday night, Kansai Electric Power Co.’s Oi No. 4 followed Oi No. 3 in a maintenance shutdown, and for the second time since March 2011 Japan is nuclear free.

But at what cost? On top of the ¥47 billion ($472 million) spent dealing with the leaks and contamination at Fukushima, and a ¥1 trillion capital injection into plant operator Tokyo Electric Power Co., Japan must now import its missing energy needs.

Liquefied natural gas, oil and coal must all now provide the heat and light Japan needs. Imports of LNG, especially, have increased substantially since a tsunami struck the Fukushima plant–an 11% increase in 2012 after a 12% rise in 2011 have together cemented Japan’s place as the world’s number one market for LNG.

In the same time, the cost of these shipments has increased by 75% as the yen weakened against the U.S. dollar.

So no wonder Japan is seeking new suppliers, preferably some who would be happy to provide at lower prices. As The Wall Street Journal’s Mari Iwata reports, last week’s LNG Producer-Consumer Conference in Tokyo was the venue for some aggressive courtingof Asian buyers by emerging North American suppliers.

For now, thanks to new capacity coming online in recent years, supply is abundant. But with the International Energy Agency warning of unprecedented tightness this year and next as that Asian demand increases yet further, the period of low, low prices that Japan so desperately needs may be short-lived.

Recent evidence suggests that a fall in LNG use–particularly a cost-related fall–will lead to greater burning of coal. Bad news for the huge LNG-export projects planned in Australia, all of which are pointed firmly at the Asian markets, but potentially good news for struggling thermal coal producers Down Under.