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CHICAGO, Oct 24, 2011 (BUSINESS WIRE) — Driven by a need to bolster overseas energy reserves and an interest in unconventional resource development know-how, national oil companies (NOCs) are playing an increasing role in global energy M&A deals. Fitch expects this trend to continue, as access to North American shale resources and drilling technology grows in importance for state-run energy firms looking to develop shale resources in other parts of the world.

For companies such as Sinopec and CNOOC in China and South Korea’s KNOC, constrained domestic oil and gas supplies relative to downstream production requirements have led to a broad investment push into the global upstream, with M&A and joint venture development spending spread across resource-rich areas of Latin America, Africa, and the shale and oil sands regions of the U.S. and Canada.

In addition to oil and gas reserve acquisition, the need to gain access to technology in activities such as horizontal drilling and hydraulic fracturing (“fracking”) will likely drive continuing interest in North American acquisitions.

Sinopec’s offer to buy Daylight Energy of Canada for C$2.2 billion earlier this month may signal a trend toward more active resource acquisition efforts in Canada. This is particularly true in light of investments in Canadian pipeline and port facilities to enable the export of liquid natural gas (LNG) to China. The Daylight deal follows similar acquisitions announced earlier by CNOOC in its planned acquisition of Opti Canada for $2.1 billion and PetroChina’s Canadian gas joint venture investment, valued at $5.4 billion.

Strong liquidity positions and good access to capital should support more M&A activity by state-run firms, particularly if equity valuations for North American exploration and production firms remain depressed.

After CNOOC’s 2005 bid to acquire Unocal led to strident opposition in the U.S., Chinese firms have steered clear of large U.S. energy deals. However, state-run firms will probably pursue more joint venture investments in North America, particularly in shale basins where recent discoveries have led to major project announcements by firms such as Shell and Chevron.

Interest in U.S. and Canadian shale resources has led other long-established state-run companies like Norway’s Statoil to announce acquisitions recently. Statoil’s planned $4.4 billion cash takeover of Brigham Exploration, announced last week, reflects the national company’s need to supplement depleting North Sea oil reserves. The deal will allow Statoil to gain access to shale oil and gas resources in the Bakken Shale region of North Dakota and Montana.

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By Ben Geman – 10/18/11 02:45 PM ET

A divided Commodity Futures Trading Commission voted along party lines Tuesday to impose new restrictions on speculative trading in energy futures markets.

The rules, required under last year’s Dodd-Frank law, are aimed at reigning in speculative Wall Street trading that some allege has driven up oil prices and worsened market volatility in recent years.

The rules impose “position limits” on the amount of futures and swaps contracts for oil and other commodities that traders hold.

“While I’d have an even tougher rule in many respects if I were the only author, this is nonetheless a very strong, needed and imperative rule to ensure more efficient and effective markets devoid of fraud, abuse and importantly, manipulation,” Bart Chilton, a Democratic member of the five-person CFTC who has been the body’s most outspoken advocate of imposing the rules, said in a statement.

Chilton voted for the rule along with CFTC Chairman Gary Gensler and Democratic member Michael Dunn.

The rule sets limits on contracts for oil, natural gas and two other energy contracts, as well as a slew of agricultural and metals contracts.

Republican CFTC members Jill Sommers and Scott O’Malia opposed it. Sommers said she’s not opposed to limits per se and noted the regulators have set limits in some markets for years.

But she laid out several concerns with the rule, including fears that exemptions for “bona fide hedgers” — that is, companies such as utilities and manufacturers that use trading markets to manage price risks — are too narrow.

More broadly, she said the CFTC is “setting itself up for an enormous failure.”

“I do not believe position limits will control prices or market volatility, and I fear that this Commission will be blamed when this final rule does not lower food and energy costs,” she said.

But Sen. Bernie Sanders (I-Vt.), who has bashed delays in the rules, has long argued that speculation has an outsized effect on energy prices.

In a statement, the liberal senator called the rules a “positive development” but said they’re too weak.

“Under this rule, a single Wall Street speculator will still be allowed to hold positions equal to 25 percent of the physically deliverable supply of crude oil, gasoline, and heating oil. That’s not enough,” Sanders said.

He noted, however, that the rules enable tightening of the limits in the future.

“I will continue to urge the CFTC to use this provision to impose stricter speculation limits,” Sanders said.

The long-delayed rules have proven controversial among the CFTC members and prompted widespread interest among a range of industries that participate in energy and other commodity markets.

Chilton, while noting he wanted tougher rules, said the new limits are nonetheless significant.

“The rule sets federally enforced limits, for the first time ever, on the amount of concentration anyone may control in energies and metals,” Chilton’s prepared remarks state.

He noted that limits have been in place in some agricultural markets for decades.

“In these other markets, we have seen cases where one trader holds 30, 35 and even 40-plus percent of a market. That can be, and I believe has been at times, manipulative. This rule will put a stop to that,” Chilton said.

While the commission approved the limits 3-2, Dunn criticized the rulemaking and said he voted in favor only because the Dodd-Frank law mandated the restrictions.

He called the limits a “sideshow.”

“To be clear, no one has proven that the looming specter of excessive speculation in the futures markets we regulate even exists, let alone played any role whatsoever in the financial crisis of 2008,” Dunn said in his opening remarks. “After we implement position limits, in all likelihood, the prices of heating oil and gasoline will not drop precipitously as some have strongly suggested.”

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NEW YORK/HOUSTON (Reuters) – On paper, it’s the kind of arbitrage deal that oil traders dream of: buy crude at $85 a barrel in Oklahoma, truck it 550 miles south, and sell it to a Gulf coast refiner for $110.

In practice, the crude trucking trade – a measure of last resort as pipelines, trains and barges are maxed out — has proved tantalizing but elusive. Just ask Robert “Bo” Collins, the former NYMEX president and hedge fund manager, or the teams at global energy trading titans Mercuria and Vitol.

Collins, who presided over the home of the benchmark U.S. oil futures contract a decade ago, has tried in vain to organize a fleet of trucks to haul crude out of Cushing, Oklahoma, down to the U.S. Gulf Coast, where he could sell it for $25 a barrel more.

An in-depth investigation by Reuters shows the trucking arbitrage that has had traders buzzing from London to Houston remains, for now, just speculation. Talk that 10,000 barrels per day (bpd) or some 50 trucks are plying the 12-hour route is unfounded, according to interviews with over a dozen sources.

While the unprecedented discount of benchmark U.S. crude prices, delivered into the Cushing storage hub, relative to European Brent, the prevailing price for U.S. refiners on the coast, has triggered a surge in river and railway transit, the trucking option has been a bust.

The failure of veteran traders to capitalize on a seemingly glaring opportunity is all about logistics, not economics.

While the overall trucking sector remains depressed, there’s an acute shortage of the tankers and qualified drivers needed to haul crude; most that are available have been quickly locked into remote shale oil fields in Eagle Ford, Texas, and the Bakken of North Dakota, where the trucks are essential to get oil from the well-head to nearby pipelines.

Even so, the active exploration by traders of the long-haul shipment of crude by tanker truck — a means of transportation that hasn’t been used extensively in the oil sector in decades — demonstrates the extent to which the massive distortion in the U.S. oil market has upended trading patterns.

As a glut of crude from Canadian oil sands depresses prices in the Midwest, producers and trading companies hoping to push their oil to the premium-priced import hubs on the coast have already tapped alternatives like rail and river barges this year due to a lack of southbound pipelines.

Historically, imported crude moved north from the Gulf Coast into the Midwest, but the influx of Canadian oil production has changed the game for the United States.

Trucking is the most extreme option for would-be arbitrageurs aiming to reverse that flow.

“You don’t truck if you can rail and you don’t rail if you can pipeline,” the CEO of Canadian pipeline firm Enbridge, Patrick D. Daniel, told Reuters last week.

But the potential profits are too tempting not to try. London-based Brent and U.S. crude, often referred to as WTI (West Texas Intermediate), have normally traded within a dollar of each other, but this year Brent’s premium has blown out to more than $25 a barrel.

However, some two dozen trucking firms and traders contacted by Reuters presented little evidence to suggest that any company has managed to make it work on a major scale yet.

Truckers are revving up, but for the shale industry, not the long-haul game.

“The Brent-WTI spread arbitrage opportunity may certainly tempt a few to evaluate investing in trucking oil out of Cushing,” said Collins, who went on to run two unsuccessful hedge funds after leaving the NYMEX in 2004.

“But I believe close examination of the operational challenges would deter any new major activity.”

He said he had shelved the project for now.

SHALE THE REAL BOOM FOR TRUCKERS

Estimates for the normal cost of hiring a tanker truck to drive the Oklahoma to Gulf roundtrip vary widely from $7 to $19 a barrel, or roughly $1,300 to $3,500 a truck.

One tanker operator broke down his estimated costs like this: two drivers at an average salary of $22 an hour each adds up to more than $1,000 in wages alone; another $700 for diesel fuel at $3.75 a gallon; a further $500 for the truck lease, insurance, maintenance and depreciation costs. About $2,300 before a dime of profit.

But assuming a $25 price spread on 185 barrels, there could still be money to be made on an arb of $4,600 per trip.

It’s not that the tanker industry wouldn’t love the trade. But it is simply stretched to the gills after a recession-induced collapse in business was followed by the biggest surge in demand the industry has ever experienced.

The tanker business has already rebounded to pre-recession levels, according to American Trucking Association data, thanks to the biggest boom in the U.S. oil business since the deepwater Gulf of Mexico.

The production of shale or ‘tight’ oil in the United States has soared from almost nothing to around 700,000 bpd in just three years as new drilling techniques and fracking technology opened up frontier reservoirs. It could hit 2 million bpd within five years, according to some in the industry.

Much of it is in previously undeveloped regions like southwest Texas and North Dakota, far from existing pipelines, meaning trucks are the best means of getting crude from sometimes remote wells to market distribution points.

Deliveries of crude to refineries by truck last year reached nearly 200,000 bpd, the highest since 1993, according to Energy Information Administration data. Volumes are up nearly 50 percent from seven years ago.

“There is a huge demand for trucks right now. If they could convert an ice cream truck to haul crude they would,” said George Jordan, the chief operating officer of Central Crude in Louisiana. The firm is expanding next month from two to 10 trucks in Eagle Ford — a rich new shale play in southwest Texas — and may double that again within 18 months.

Demand is so high that Central Crude can make between 50 to 100 percent more per truckload of crude they haul in Texas than they do in Louisiana, with fees as high as $5 a barrel, said Joe Milazzo, its vice president of crude supply.

That works out at almost $1,000 for every short-haul truck journey from wellhead to storage terminals or pipelines, which they can do several times a day. Eventually a new network of pipelines being built across Eagle Ford will reduce demand for the tankers, but that will take at least another two years.

“There will be pressure on trucking margins in Eagle Ford as infrastructure improves in the future, but there are so many small wells being drilled that are too insignificant to be connected to a pipeline that there will always be demand for trucks,” Milazzo said. “We’re in it for the long haul.”

Schneider National, one of the largest trucking firms in the United States, is hiring 300 more drivers to help meet booming demand from shale producers alone.

There are 27,000 registered interstate tanker trucks in the United States, according to the Department of Transportation, enough to haul almost 5 million barrels of oil. But the majority are dedicated to shipping refined products rather than crude oil regionally to gas stations.

Driver salaries are also rising. Although employment in the trucking sector fell 14 percent to the lowest level in over a decade following the recession, there are not enough drivers with the requisite Hazardous Materials (Hazmat) trucking license to meet demand, industry sources said.

Milazzo estimated that driving from Cushing to the Gulf would be at least at 20-hour round trip, requiring two drivers, sleeping cabs, and an empty tanker on the route back. Salaries would be higher still as drivers would be away from home for at least one night.

Additionally, trucking industry sources said truck and trailer manufacturers are already struggling to meet demand, with an 8-12 month wait time for new vehicles.

New sales of heavy trucks slumped by two-thirds after the onset of the recession, axing capacity.

Tanker firms would require long-term commitments from traders to lure them away from the shale industry, commitments they’re unlikely to get, said Bradley Olsen, an analyst at investment bank Tudor, Pickering, Holt & Co in Houston, Texas, which advises the energy industry.

“There’s a large opportunity cost for the truckers to think about,” said Olsen, adding some companies may be making more than $10 per short-haul trip in Eagle Ford.

“No one is convinced about how long the (Brent-WTI) spread might last. It could be gone in a year. Are you going to leave lease hauling (shale crude) and possibly lose customers?”

Pipeline companies are also eyeing the opportunity a plan links from Cushing to the Gulf Coast within two or three years, which would render the hassle and investment of trucking the same route unprofitable.

Having spoken to almost every major mid-stream companies in the region, Olsen found none were trucking in bulk.

“Cushing cannot load 100,000 bpd of trucks at 200 barrels a time. There is no real way to deploy it on a large scale.”

ARE TRUCKS MOVING?

No hard data exists on how much may be moving. Tanker loads would be easy to miss — or confuse with local haulers — on heavily traveled routes across Oklahoma, Texas and Louisiana.

Terry Brannon, the chief of police in Cushing, Oklahoma, said the level of truck traffic in and around Cushing does not appear to have changed. “We see the normal flow of trucks,” he said.

Even so, analysts have already factored small but tangible volumes being hauled south. Barclays Capital and Goldman Sachs estimate around 5,000 to 10,000 barrels per day (bpd) are moving by truck from Cushing to the Gulf. This would require at least 25-55 trucks making the 1,000 mile round trip daily.

Identifying those behind the trade is far trickier.

Oklahoma-based Blueknight Energy Partners, co-owned by commodities trading giant Vitol and one of the largest trucking and storage operators in the Midcontinent oil patch, seems a likely candidate given its 6.7 million barrels of storage at Cushing and 170 crude oil transport trucks.

But while it has sometimes trucked Cushing crude to higher priced markets or distribution terminals linked to the Gulf, it hasn’t made it all the way to the coast, a senior source with knowledge of Blueknight’s operations told Reuters.

Blueknight and Vitol did not respond to inquiries.

Two industry sources also pointed to 4K Fuel Supply in Houston, Texas, which moves refined oil products short distances by truck in the Houston area. But the firm told Reuters it had not moved into trucking crude.

Industry sources also highlighted Swiss-based energy trader Mercuria, which owns storage space and tank racks at the Cushing storage hub. But the available evidence indicated Mercuria was only moving crude 30 miles by truck to a rail siding in Stroud, Oklahoma.

Premier Trading & Transportation is running three to five trucks for Mercuria from the Deeprock Energy Resources LLC terminal at Cushing to Stroud, sometimes making the 60-mile roundtrip four or five times a day, said Randy Collum, manager of trucking operations. The crude is then railed south.

“We had to lay extra pipelines and different meters at Cushing (to load the crude into the trucks),” Collum said. “It works for now. The price difference between crude on the Gulf Coast and the price in Cushing is driving it. It’s profitable or we wouldn’t do it,” Collum said.

Mercuria spokesman Patrick Prendergast said rail and barge were “a better logistical fit for the longer distance moves at this time,” adding Mercuria was unaware of any barrels being trucked direct from Cushing to the Gulf Coast.

Other estimates are far lower than those provided by the banks. One operations officer at a major logistics firm in the Midwest, who asked not to be identified, said he was aware of a small number of barrels moving by truck, but estimated it at less than 1,000 bpd.

He declined to give the names of the firms citing client confidentiality, but said they were small, local, independent traders.

So the spread remains just that — tempting, but out of reach.

“In theory it can be done. You can make money, it would be great to do this,” said Jordan at Central Crude. “But for the moment all our trucks are tied up elsewhere, and it’s a risky proposition knowing how fast that spread can move.”

(Reporting by David Sheppard and Bruce Nichols; additional reporting by Christopher Henwood; editing by Jonathan Leff and David Gregorio)

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Long-time followers of Global Resource Investments Founder and Chairman Rick Rule know he is an energy bull. He sees increasing demand as an inevitable outcome of global mathematical formulas. “Around the world, in emerging and frontier markets, 3.5 billion people aspire to your lifestyle, but haven’t been able to compete with you for the last 150 years because they haven’t had any money,” he explains in a recent webcast. “As those people become more free, they become more rich and increasingly they are able to compete with you. In the process, these 3.5 billion people will increase their per-capita consumption of energy. The demand curve in energy relative to GDP is breathtaking. As people on the bottom of the economic pyramid get more money, what they do with it is very energy-intensive. So, GDP gains at the bottom of the demographic pyramid lead to disproportionately high gains in energy consumption.”

Rick sees inverse trends on the supply side. “Energy trades on a worldwide basis are led by oil, the supply of which is declining as a function of peak oil—which is partly a scientific and partly an economic calculation—and, more importantly, by a reduction in sustaining capital expenditures by national oil companies. Mexico, Venezuela, Ecuador, Peru, Indonesia and Iran are large petroleum exporters that may not be exporting any oil at all in five years. When you have worldwide import demand growing at 1.5% or 2%, compounding a supply that is declining by 25% or 30%, the potential intersection of those two facts in the market could be explosive to the upside.” He acknowledges some possible supply variables in the world, but believes the overwhelming equation stands. “A million barrels a day of Libyan crude back on the market would provide some moderation of the supply shortfalls. And a return of Iraqi crude on the market would also be useful. But my own personal belief is that neither of those two sources of supply can mitigate the supply shortfalls that we’re going to see from the national oil companies.”

Rule’s bullish oil price outlook extends to liquefied natural gas (LNG). “LNG is, increasingly, a substitute for oil. In light of a combination of the reduction in the Japanese nuclear generating capabilities and South American supplies going off line, we expect worldwide LNG supplies to be fairly tight on a going forward basis.” That is good news, he says, for North America, which has a robust domestic natural gas industry. “The consequence of the pricing umbrella led by oil and import substitution of gas molecules will return gas to profitability in the next two years,” he predicts.

Rick is not predicting a direct ascent in natural gas prices. The theme of the webcast is volatility. That painful reality goes for the overall market as well as the energy sector. “I think gas will trade in a band between about $3.00/MMBtu on the low side and $7.00/MMBtu on the high side. Any dollar north of $5.50/MMBtu and these gas producers start making real money.”

Rule is also bullish on opportunities on the service side in the oil and gas business. “We are going to need to do an awful lot of drilling worldwide to keep up with our demand for oil and gas. Increasingly, the places that produce oil—places like Libya and Iraq—don’t have the expertise and services to develop and produce their reserves. Large service companies are beginning to act like mini-majors, providing contract services to national oil companies or multi-national oil companies. Therefore, we are bullish about some of the service companies.”

What isn’t appealing to Rick in the sector? “We wouldn’t be so attracted to companies that have large exposure to North American or Western European refining and marketing because we expect those margins to be continually constrained. But, companies that are leveraged to upside production we like a lot. We particularly like the juniors and we particularly like the Canadian juniors because Canadian institutions are on strike in terms of buying companies producing less than 5,000 barrels a day with market capitalizations less than $500 million.” Rule points to a matrix of valuation measures that changes markedly when companies get to a certain size, reevaluating them as they get larger and eventually making big companies out of them, which can yield takeover premiums. “This market cap arbitrage is going to be an important theme on a going forward basis,” he says.

Rule is beginning to see uranium stocks return to levels where he thinks they are safe to buy again. Global got into the uranium sector starting back in 1999. “We were spectacularly right,” he recalls. “Then, in 2005/2006, when the uranium sector experienced its, sorry for the pun—boom, we were out of the way.” Now he sees the tables turning again. “Uranium seems to be a four-letter word now. People’s expectations from ’05 and ’06 were impossibly high and as a consequence, they were disappointed. That disappointment was exasperated by the events in Japan.” Rule sees four or five uranium juniors that he thinks are quite attractive. He may not be alone. Apparently Cameco Corp. (TSX:CCO; NYSE:CCJ) agrees as evidenced by its recent hostile takeover offer for Hathor Exploration Ltd. (TSX.V:HAT). “We think this is the first of several consolidations on a worldwide basis in the uranium business,” he predicts. “Now is the time to begin to establish positions in the uranium sector.” In Rule’s crystal ball, uranium energy will contribute a growing share of worldwide electrical generation, not because people are less afraid of it, but simply because when they flip a switch, they want the light to go on. And without uranium, the light won’t go on in many parts of the world.

Rick also continues to be attracted to some alternative energy sectors—run-of-river, hydro and geothermal. “People ask me at conferences, ‘Rick, what is wrong with the geothermal sector?’ The answer is nothing. There is nothing wrong with the sector. What has been wrong with the sector’s performance is that the management teams who have entered the sector have been, let’s say, challenged—implementation-challenged.” Rick sees three issues plaguing geothermal: long lead time to production, capital-intensive preparation and implementation. Rule sees a light on the horizon for all three of these problems. A number of geothermal projects are already five years into their seven-year development cycles. That is two-thirds to three-quarters of the way to completion. At some of these companies, the capital has already been spent and they are selling at discounts to book. That suggests that the cost of capital is extraordinarily low on a going forward basis because it’s already been spent. That leaves implementation and management. After a 20-year bear market in energy, precious few alternative energy management teams were left to handle the investments that have been made in the last 10 years. “All other things considered, if you have lost faith in the sector, are disgusted and looking to exit for tax losses, I strongly suggest that you do it now. But, do it with the knowledge that I will be the buyer,” he jokes.

Regardless of the sector, Rule sees timing as one of the deciding factors in successful portfolio management. “I would encourage people who have portfolio companies with substantial losses, but other portfolio gains this year, who are going to do tax loss selling, to do it now. Beat the rush,” he advises. “The tax loss selling we are going to see in November and December of this year—particularly if we experience more volatility between now and then, which I think is inevitable—is going to be extreme. If you bought a stock for $2.00 and the stock is at $0.50 now and you think you are going to want to sell it, you might want to sell it now because you might only get $0.30 or $0.35 if you sell it later.” Of course, the inverse applies on the buy side. “If there are companies that you are attracted to that have gone down in price this year, the existing shareholders of those companies may very well be taking tax losses in November and December. So, build yourself a shopping list—or borrow our shopping list—and look for names that you would like to buy in November or December.”

Global Resource Investments (GRI) founder and CEO, Rick Rule began his career in the securities business in 1974 and has been principally involved in natural resource security investments ever since. He is a leading American retail broker specializing in mining, energy, water utilities, forest products and agriculture. Rule’s company has built a sterling reputation for its specialist expertise in taking advantage of global opportunities in the resources industries. Last month, Rule closed a landmark deal with Eric Sprott, another famous powerhouse in the arena. With GRI now a wholly owned subsidiary, Sprott Inc. manages a portfolio of small-cap resource investments worth more than $8 billion and boasts a workforce of more than 130 professionals in Canada and the U.S. This article is based on Rule’s August 31 Global Resource Investments webcast.

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By Cara Bayles

Gulf industries have expressed outrage over the Obama’s administration to waive a key piece of federal legislation that protects the local maritime industry from foreign competition.

In June, the administration issued a blanket waiver of the Jones Act which requires that domestic cargo move on U.S.-flagged ships, unless they are unavailable during a national security crisis.

Foreign ships moved more than 30 million barrels of oil from federal strategic reserves in Texas and Louisiana after political turmoil in Libya earlier this summer sparked concern about energy shortages.

Don Briggs, president Louisiana Oil and Gas Association, called the policy “unconscionable.”

“Mariners need these jobs and vessels need to go to work,” he said. “This goes right in the face of the shipping industry and the oil-and-gas industry. It really makes no sense.”

At least 46 foreign ships moved the oil. After industry protest, the administration promised to review applications on a case-by-case basis. Still, last week the New York Times reported that that vast majority of contracts went to foreign-flagged ships.

Anne Burns, spokeswoman for the American Waterways Operators, said American ships were “willing and able to move the oil,” but that the administration began granting waivers based on lot sizes of 500,000 barrels or more, giving contracts to larger foreign-flagged ships that could move more oil. In all, she said, there are 31 U.S. vessels available that have a combined capacity of 4.2 million gallons.

A White House official said that the larger lot sizes were necessarily to rush to market the large volumes requested by oil companies. In order to increase the ability of U.S. ships to compete for those contracts, the administration lowered the minimum bid to 300,000 barrels, the official said.

Jim Adams, president of the Offshore Marine Service Association, said that foreign ships have a cost advantage over domestic ones, because they aren’t subject to the same regulations.

“They don’t play by the same rules as U.S. flag companies,” he said. “There is plenty of capacity to help move this oil on us tankers. Americans should have had the first bite of the apple.”

He added that tapping into federal reserves seemed “hypocritical,” since the administration recently had “its boot on neck of local industry” with a moratorium on off-shore drilling.

Merritt Lane, president of Canal Barge, a New Orleans company that works in the region, and is currently building two barges at Gulf Island Fabrication in Houma, said the policy sets a dangerous precedent for the region. His company would not have been eligible for the work, because it doesn’t man seafaring barges. But Canal is a U.S.-flagged operator.

“For any of us that work under the Jones Act to see it being flaunted in such a cavalier manner is concerning,” he said.

In a bipartisan letter to the president last week, some lawmakers, including both the state’s senators, called the policy “a stain on the administration’s determined effort to create jobs and improve the economy here at home.”

A staffer from Senator Mary Landrieu’s office said the matter was both a federal and a constituent concern. The reserve oil was scheduled to be moved by the end of August, but the senator hopes the letter discourages the administration from waiving the Jones Act in the future.

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HOUSTON, Aug. 30

By Sam Fletcher

OGJ Senior Writer

Despite the pre-storm hype by government officials and national media concentrated along the East Coast, Hurricane Irene proved a fizzle rather than ferocious, with virtually no impact on energy prices, with crude up 2% Aug. 29 in the New York market on optimism for the economy and oil demand.

Most petroleum processing and distribution facilities on the eastern seaboard came back online almost immediately as the expected storm damage and disruption failed to materialize over the weekend. “Magellan Midstream Partners still has two facilities in Wilmington, Del., and New Haven, Conn., closed pending further inspection. No updates have been released for the Providence NGL terminal for Enterprise Products Partners, and Kinder Morgan Partners’ petroleum terminal in Carteret, NJ, remains closed pending further inspection,” reported analysts in the Houston office of Raymond James & Associates Inc. on Aug. 30. “In summary, it remains business as usual for these partnerships, with procedural inspections to bring these facilities back online.”

While the mayor of New York fretted about a possible storm surge up the city’s East River, the only surge witnessed by Wall Street was in the Standard & Poor’s 500 Index performance, reported Olivier Jakob at Petromatrix in Zug, Switzerland.

“Historical volatility in the S&P 500 remains extremely high, and with the current high correlations between crude oil prices and the S&P 500, it is difficult in any day void of significant oil inputs for oil prices to ignore the price swings in equity. However, with a UK summer bank holiday yesterday and Irene keeping some traders at home or traveling to the beach mansion to check for damages, the volume traded in oil was extremely low, and that makes it harder to read yesterday’s price evolution,” he said.

Raymond James analysts, however, said natural gas prices fell more than 2% as post-hurricane power outages curbed demand and forecasts called for milder weather.

Meanwhile, Reuters news service reported an oil tank on fire at the Es-Sider oil export terminal, Libya’s largest, which loaded 450,000 b/d prior to the uprising against dictator Moammar Gadhafi. One official was quoted as saying the terminal—controlled by the Waha Oil Co. joint venture under ConocoPhillips, Marathon Oil Corp., and Hess Corp.—was damaged by gunfire days ago. A second damaged tank at the Brega export terminal was reported smoldering.

Jakob said, “The main global input yesterday was a stronger-than-expected increase in US consumer spending, up 0.8% in July compared with a negative 0.1% in June. The other side of the coin, however, is that real disposable income dropped by 0.1% compared with [a gain of] 0.3% in June. We continue to believe that the high prices for gasoline and distillates will continue to challenge real disposable income and economic growth. Irene being a no-show, the reformulated blend stock for oxygenate blending (RBOB) gasoline crack to Brent suffered yesterday and if more losses are printed on the gasoline crack, we will start to enter the zone where US refinery margins will be negatively impacted.”

Energy prices

The October contract for benchmark US sweet, light crudes climbed $1.90 to $87.27/bbl Aug. 29 on the New York Mercantile Exchange. The November contract increased $1.87 to $87.27/bbl. On the US spot market, West Texas Intermediate at Cushing, Okla., was up $1.90 to $87.27/bbl.

Heating oil for September delivery barely advanced 0.01¢, closing essentially unchanged at a rounded $3.01/gal on NYMEX. RBOB for the same month declined 2.82¢ to $2.91/gal.

The September contract for natural gas fell 7.4¢ to $3.86/MMbtu on NYMEX. On the US spot market, gas at Henry Hub, La., dropped 7.2¢ to $3.92/MMbtu.

In London, the October IPE contract for North Sea Brent advanced 52¢ to $111.88/bbl. Gas oil for September gained $13.75 to $963.75/tonne.

The Organization of Petroleum Exporting Countries offices in Vienna are closed Aug. 30-31 for a religious holiday with no update on the average price for the group’s basket of 12 benchmark crudes.

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By Steve Gelsi

NEW YORK (Dow Jones) — Despite a big drop in oil and stock prices in recent days, U.S. energy companies bearing down on the country’s shale fields have yet to waver from plans to add staff this year to boost domestic production.

The industry is hiring as it brings new U.S. supply on line and demand grows from power-generation companies switching to natural gas from coal or fuel oil.

“Our industry is competing for talent,” said Jim Haynes, vice president for U.S. operations at Spectra Energy Corp. (SE) “We continue our hiring mode.”

Spectra Energy, for example, expects to add staff as part of plans by the pipeline firm and its affiliates to add up to $10 billion in infrastructure in the next five years.

The Independent Petroleum Association of America projects as many as 200,000 new jobs in the energy patch from hundreds of oil and gas producers in 2011.

“I don’t think the threat of a double-dip recession will stop many companies from hiring,” said Jeff Eshelman, spokesman for the trade group of oil and gas producers, once known as “wildcatters.”

“Overall, the natural-gas industry is one that is adding people, not scaling back,” Haynes added. “We’ve seen at least a 15% increase, industry-wide, over the past several years, even during the downturn.” Last year, Spectra hired 130 people and it’s already brought on about 129 this year.

Dave Pursell, managing director and head of securities for Houston-based research firm Tudor Pickering Holt & Co., said an analysis of shale-gas fields in the United States revealed that nearly all remain profitable with oil at $80 a barrel or less. On July 25, oil was still $100 a barrel; on Tuesday, crude futures rose 1% to $82.

“The velocity of the drop has gotten people’s attention,” according to Pursell. “But companies aren’t going to change their strategic hiring based on a two-week move in oil.”

To be sure, the industry contracted during the 2008-09 financial crisis as it became more difficult for companies to get funding for their drilling programs, but so far, that doesn’t seem to be happening, he said. The 2008 crisis, for instance, saw a much steeper drop in natural-gas prices than now.

Engineers wanted

While the U.S. jobs figures for July came in better than expected, the overall picture for employment remains moribund — outside of the energy sector.

Among the hotter areas for employment growth: Some 50,000 job additions this year are expected for the Barnett shale of Texas, and 48,000 in the Marcellus shale of Pennsylvania, West Virginia, Ohio and New York, according to the IPAA.

Besides the Barnett and Marcellus shales, U.S. energy companies plan to beef up rolls in the Haynesville shale of Texas and Louisiana, the Eagle Ford of South Texas, the Bakken of North Dakota and Utica formations of Ohio.

Hiring activity also has picked up as natural-gas firms focus on more labor- intensive oil drilling; plus, companies need to drill to hold acreage under most of their leases with property owners, Tudor Pickering’s Pursell pointed out.

Another incentive to drill is to get higher-priced Louisiana sweet crude, which fetches a price near the Brent crude level of $100 a barrel, he said. ” Companies are drilling because they want growth. And drilling for oil still makes money with oil below $80 a barrel in most areas.”

Some of the most sought-after job candidates in the energy sector right now are petroleum engineers — a specialization in charge of technology used to maximize returns from wells, according to Apache Corp. (APA) spokesman Bill Mintz.

“One area of concern in the industry is that a lot of petroleum engineers are in their 50s and expected to retire,” he said.

Chip Minty, spokesman for Devon Energy (DVN), said the company currently has more than 300 openings right now and no plans to curtail hiring.

“The swing we’ve seen in oil and equity prices does not have a bearing on our long-term operational objectives,” he commented. “We do analysis as we put together our budget. We use market prices that are quite conservative. Even if oil and natural gas dropped below where they are today, we’d still be looking at wells that are economical.”

Apache’s Mintz said the independent energy company’s ranks rose to 4,500 in 2010 up from 3,500 in 2009, and more jobs are coming in 2011. “We’re continuing to hire. We’ve got a lot going on in all of our regions.”

The company has been recruiting graduates from the Colorado School of Mines, Texas A&M University, Texas Tech University, the University of Oklahoma, University of Texas and the University of Tulsa.

Asked if Chesapeake Energy Corp. (CHK) planned to scale back hiring this year in the wake of Monday’s big selloff in the equities market, company spokesman Jim Gipson said “nope,” and referred to a local newspaper report about economic expansion in Oklahoma City, Chesapeake’s headquarters.

Original Article

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Releasing oil from the Strategic Petroleum Reserve makes sense in time of emergency, natural disaster or a major disruption in supplies. None of those events have occurred, which makes the decision yesterday by President Barack Obama to tap the reserve puzzling.

Obama, in concert with the International Energy Agency, plans to draw 2 million barrel a day during the next month from U.S. and international reserves. Oil prices plunged.

Perhaps that was the desired effect. The argument offered by Obama and IEA officials was that the released oil would offset the reduced supply of crude from Libya. The release also coincides, the Department of Energy said, with the onset of the peak U.S. summer driving season.

But amid a run of gloomy economic news, it’s hard not to imagine that other motives were at work. The Federal Reserve on Wednesday lowered its growth forecast for the year. Unemployment is heading in the wrong direction. The U.S. housing market still is in decline.

This is only the fourth time since the petroleum reserve was established after the mid-1970s oil crisis that a U.S. president has tapped it. The others were in 1991 during the first Gulf War; in 1996-97 to help reduce the federal deficit; and in 2005, after Hurricane Katrina knocked out drilling rigs across the Gulf of Mexico.

Over the years Congress has adopted rules making it easier for the president to release oil at times of high prices. But with crude at about $95 a barrel before the announcement — well below the record of $147 in 2008 — that hardly seemed to be the case.

What’s confounding about the reserve release is that it doesn’t seem to meet the president’s professed standards. “The reserve should only be used in the event of an emergency,” Obama said in 2005. Unless the administration can make a persuasive case that disaster lurks, we will be compelled to face a situation more corrosive than rising gas prices or the lack of a comprehensive energy policy — the sense that our leaders are making short-sighted decisions for political gain.

Original Article