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QEP Resources plans to move more than 30 employees from its Oklahoma City office to its Tulsa location. In addition, the company plans to add another 20 employees in Tulsa.

The expansion will give QEP a total of 130 employees locally by the end of 2012.

“QEP Resources is committed to becoming an employer of choice in Tulsa,” Jeff Tommerup, vice president for the company’s southern region, said in a news release. “Currently, we source more than half of our natural gas production from the company’s southern region properties, positioning Tulsa as a strategically important center of operations.”

The QEP announcement follows other expansion moves in Tulsa by two Houston-based, energy-related companies. Apache Corp. has said it plans to add to its Tulsa workforce after buying oil and gas properties in western Oklahoma and the Texas Panhandle, and oilfield services provider Baker Hughes Inc. is building a new research and development center at its Claremore site.

“Northeast Oklahoma continues to outpace the nation in many areas of economic development and job creation, and our strong legacy of energy sector employers are bolstering that growth,” Tulsa Metro Chamber President and CEO Mike Neal said in a statement. “We know that QEP will continue to thrive in the Tulsa region, and we look forward to continued success from this leading energy company.”

WPX Energy Inc., a Tulsa-based oil and gas producer, has added 31 employees locally to boost its Tulsa workforce to 580 so far this year. WPX is a spinoff of Williams Cos. Inc.

QEP Resources’ southern region operations include 25,300 net acres in the Granite Wash play of the Texas Panhandle, 77,000 net acres in the Woodford Shale of Oklahoma and 50,000 net acres in the Haynesville Shale of Louisiana and Texas.

Companywide, QEP’s production averaged 803 million cubic feet equivalent per day in 2011.

The southern region produced about 40.6 billion cubic feet equivalent, compared with 38.8 bcfe for the same three months in 2011, according to QEP’s latest earnings release.

QEP operates 27 working wells in the Woodford’s Cana play as of the first quarter.

The company plans to accommodate the job growth by expanding its One Warren Place office space to three floors by next month.

Questar Corp. separated QEP Resources with a tax-free spinoff to its shareholders in 2010.

“We are very pleased that QEP plans to expand its Tulsa-area operations as the company pursues growth and opportunities in the Tulsa region,” Mayor Dewey Bartlett said. “Being from the oil and natural gas industry, I am especially gratified that our outreach to the energy industry is being answered.”

Tulsa’s energy sector employs more than 18,000 people and has an annual economic impact of almost $29 billion, according to data from the Tulsa Metro Chamber.

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As the Memorial Day weekend and the summer driving season approach, gasoline prices are easing. But most drivers will find prices only modestly lower than a year ago.

Nationwide, the price of a gallon of regular gasoline has been drifting lower by about half a cent a day over the last month, and energy analysts say that trend should continue over the next few weeks, in at least some states.

“Drivers are getting a respite,” said Rodney L. Waller, a senior vice president at Range Resources, an oil and gas company based in Fort Worth. “But it’s a tenuous respite based on all the changes in the global oil market and the opening and closings of refineries across the U.S.”

Gasoline prices are dropping primarily because of a decline in global crude oil prices, stemming from an easing of tensions in the Middle East and growing oil supplies, bolstered in recent months by the rapid return of Libyan oil exports and increased production from Saudi Arabia. Because oil is priced in dollars, the firming value of the dollar in recent weeks in the wake of the European financial crisis has also helped reduce prices.

The sluggish global economy has also reduced demand for oil and other commodities, particularly in Europe. Demand growth in China, a main driver of oil prices in recent years, has slowed in recent months. And while gasoline demand in the United States has diminished in recent months because of the soft economy, oil supply inventories recently reached a 22-year high.

Gasoline prices on the East Coast have fallen in part because one large refinery in Philadelphia that was scheduled to be closed by Sunoco at the end of June is now expected to remain open through at least most of the summer while the private equity firm the Carlyle Group negotiates to form a joint venture. Prospects for future gasoline prices in the region have also improved since Delta Air Lines bought an idled Pennsylvania refinery, which will probably produce more gasoline for the market by October.

On the West Coast, however, particularly around Los Angeles, gasoline prices have actually risen in recent weeks because several refineries were forced to suspend operations because of power failures and repairs to compressors. But those problems are expected to be cleared up by June, and energy experts expect prices to ease afterward.

The diverging refinery situations are reflected in the wide gap in gasoline prices from one coast to the other. The average price for regular gasoline on Thursday was $3.92 a gallon in New York but $4.31 a gallon in California.

The national average price for a gallon of regular gasoline on Thursday was $3.67, nearly 30 cents below the high for the year reached in early April. A year ago, the average prices stood at $3.85 a gallon.

Energy analysts say prices this summer should remain a few cents lower than last year but about 75 cents a gallon above the level in the summer of 2010. The economic effect of the lower prices is tentative because prices could easily surge again.

“Compared to 2009 and 2010, these are still stiff prices,” said Tom Kloza, the chief oil analyst at Oil Price Information Service. “People talk about this wonderful dividend, but measured against history, gasoline still represents a considerable slice of consumer disposable income.”

Mr. Kloza projected that the national average price for regular gasoline during the Memorial Day weekend would be at most only a few pennies below the current price, and would range from $3.50 to $3.75 for the rest of the summer.

Light sweet crude, the benchmark of New York trading, remained stubbornly above $100 a barrel for most of the last year. In recent weeks it has fallen to just above $90, and remained near that level on Thursday.

The spike in oil prices last year was because of the turmoil in North Africa and the Middle East, especially the loss of more than a million barrels a day of high-quality crude from Libya during the insurrection against the Qaddafi dictatorship. After easing for a few months, prices surged again early this year over fears that Iran might block supplies from passing through the Strait of Hormuz in response to tightening European and United States sanctions or the possibility of an Israeli or American attack on Iranian nuclear plants.

The sanctions have reduced Iranian exports, but increased exports from Libya, Saudi Arabia and Iraq have so far more than compensated for the drop-off in China, India and other Asian countries that have relied on supplies from Iran. Total OPEC output of oil and other liquid fuels is at a record high of 37.5 million barrels a day, despite the loss of Iranian exports.

But oil analysts warn that prices could surge again if instability interrupts production in any number of shaky producing nations. Traders were watching how a second round of talks between members of the United Nations Security Council, Germany and Iran would proceed this week, but there appeared to have been little progress. Hopes that Iran would be willing to curb its nuclear program had helped send oil prices lower, but further tightening of sanctions on Iran could send crude prices higher in the months ahead.

“If there are any problems on the supply side, as in Iran, Libya or Nigeria, then prices will be right back up,” said Michael C. Lynch, president of Strategic Energy and Economic Research. “Global inventories are not that high, and production is pretty much flat out in OPEC. A lot depends on how negotiations go with Iran.”

While production in the United States is about a million barrels a day higher than last year, now reaching 5.9 million barrels a day, several other international producers outside of OPEC are not doing nearly as well. Unrest in South Sudan has halted nearly half a million barrels a day of production. Offshore oil spills have dented output in China and Brazil, and production from the North Sea continues to decline.

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MWCC to Deploy Capping Stack for Exercise in the Gulf.
  
As part of the Obama administration’s ongoing efforts to strengthen the oil and gas industry’s ability to respond in the event of a deepwater blowout and ensure that offshore oil and gas production can continue to expand safely and responsibly, Secretary of the Interior Ken Salazar today charged the Marine Well Containment Company (MWCC) with conducting a live drill this summer to deploy critical pieces of state-of-the-art well control equipment in the Gulf of Mexico.

The exercise would demonstrate the ability of MWCC to mobilize a capping stack – a device similar to the one that stopped the flow of oil from the Deepwater Horizon’s well – in a timely fashion from its on-shore base to the deep water seabed of the Gulf.

This first-of-its-kind exercise will be overseen by Interior’s Bureau of Safety and Environmental Enforcement (BSEE), which tests capping stacks on the surface as part of its overall responsibility to enforce the tougher offshore safety requirements implemented in response to the Deepwater Horizon explosion and oil spill.

“In the wake of the Deepwater Horizon explosion and oil spill, we undertook the most aggressive and comprehensive reforms to offshore oil and gas oversight in U.S. history, including requiring the industry to have immediate access to equipment and technologies that could stop another blowout,” said Salazar. “Our safety reforms are designed to reduce the chances that a capping stack would ever be needed again, but one thing Deepwater Horizon taught us is that you must always be ready to respond to the worst case scenario. This exercise is an opportunity to deploy systems, test readiness, and train under real-time conditions.”

“BSEE has made great strides in developing an effective and strong regulatory framework to support the offshore oil and gas program,” BSEE Director James Watson said. “We have tested MWCC and capping stacks repeatedly, but putting them through their paces in the deep waters of the Gulf will give us added confidence that they will be ready to go if needed.”

MWCC is one of two consortia that provide contract access to well containment equipment to oil and gas operators in the Gulf of Mexico. This equipment is required by BSEE for drilling with subsea blowout preventers in deepwater, among other situations. The other consortium, the Helix Well Containment Group, will complete a similar deployment exercise in the future.

The demonstration will involve the field deployment and testing of a capping stack as part of a larger scenario that will also test an operator’s ability to obtain and schedule the deployment of the supporting systems necessary for successful containment – including debris removal equipment and oil collection devices, such as top hats. The capping stack will be lowered to the seabed by wire, a technique that offers the potential to be significantly faster than the deployment via pipe that occurred during the Deepwater Horizon response.

As part of the exercise, BSEE will also analyze the results from tests conducted on the sea floor. In October 2010, Secretary Salazar required that prior to receiving approval of a deepwater drilling permit, an operator must demonstrate that it has enforceable obligations that ensure that containment resources are available promptly in the event of a deepwater blowout.

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Clean Energy Fuels will build a liquefied natural gas fueling station at the Flying J Travel Plaza at Interstate 40 and Morgan Road by the end of July.

Greg Roche, the company’s vice president of infrastructure, said Clean Energy plans to build 150 stations for its natural gas highway by the end of next year.

“It’s more than the industry’s ever built,” Roche said.

Clean Energy was co-founded by Oklahoma native T. Boone Pickens, a vocal advocate of using natural gas to fuel the nation’s trucking fleet.

The California-based company got a $150 million boost last year from Chesapeake Energy Corp. to accelerate its development of public LNG fueling stations.

“There is increasing interest in natural gas as a transportation fuel, particularly in the heavy-duty truck and fleet category,” Pickens spokesman Jay Rosser said. “America’s energy future, our national security and our environment improves with the addition of each natural gas fueling station.

“This is happening because of private sector and state government leadership. With federal leadership, we can expedite this progress.”

Roche said Clean Energy plans to complete 70 natural gas fueling stations this year and 80 more next year.

There is only one planned for Oklahoma so far, but “that’s just the starting point,” he said.

Roche said LNG, which costs about $1.50 a gallon less than diesel, is best suited to heavy-duty trucks.

Clean Energy’s first choice is to partner with existing truck stops to put in LNG fueling stations, but the company will build them if necessary.

Roche said the company is aiming to get a station in place about every 250 miles on long-haul trucking routes, with additional locations inside large metropolitan areas.

Roche said the goal is to ensure drivers and trucking company owners are comfortable with putting trucks fueled by natural gas on the road because there are enough stations available.

He said eight stations have opened this year, with an additional 20 or so under construction. The rest of the stations planned for 2012 are in the design or permitting process.

Officials hope to have the Oklahoma City station completed by late this summer, Roche said.

Taylor Shinn, Chesapeake’s senior director of corporate development, said he is pleased by Clean Energy’s progress so far.

“It has been extremely encouraging to see the widespread growth, adoption and interest in natural gas as a transportation fuel, particularly for heavy-duty freight transportation,” he said. “Every day through our partnerships we see and hear about national and regional trucking companies shifting to natural gas or initiating natural gas pilot programs.”

Shinn said the natural gas highway system will encourage more companies to embrace natural gas as an alternative to more expensive diesel fuel.

“Trucking companies such as UPS, FedEx, Swift, US Foods, Central Freight, J.B. Hunt, among many others, are beginning the transition, and Chesapeake is proud to support them alongside Clean Energy,” he said.

“While these companies are a strong endorsement of the market’s future, the fact that the top 3 diesel retailers in America are working on natural gas fueling stations is a clear sign of the continued growth that is to come for natural gas as a transportation fuel.”

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Backed by four private equity firms, the architect of a new Dallas-based oil exploration and production company targeting the Gulf of Mexico predicts drilling in the region will soon top pre-Macondo spill activity on a flurry of new deals.

Brian Reinsborough, a former Calgarian who developed Nexen Inc.’s Gulf of Mexico program, said his firm Venari Resources LLC has entered the marketplace just as the rig count in the offshore play is expected to eclipse the number before BP PLC’s April 2010 well blowout that shut down drilling.

A moratorium on drilling was lifted in October 2010 but many energy companies complained a de facto moratorium caused by slow permitting dampened activity long after.

“We see the business back to almost a normal pace now. It’s a new norm, post-Macondo, but it’s much more manageable now than it was immediately after the (drilling) moratorium,” Reinsborough said on Tuesday.

Venari predicts drilling activity will balloon to 50 rigs in the Gulf of Mexico next year from the current 33 rigs, according to the Offshore Oil Scouts Association that compiles figures. By the end of 2012, the Venari forecasts the rig count will return to the 38 at the time of the spill.

“The deal flow right now in deepwater Gulf of Mexico is very high. We’re looking at a large number of deals right now and we anticipate being very active in 2012 and going into 2013,” said Reinsborough, who indicated the company does not yet have a stake in any projects, nor any drilling rights on acreage of its own.

Reinsborough dreamed up Venari as a so-called executive-in-residence since last summer at private equity firm Warburg Pincus, which has more than $35 billion in assets under management. Venari’s near-term plan is to farm into projects, acquiring non-operated stakes, he said. Then it would look to seek strategic partners in joint ventures to establish a foothold of acreage in the deepwater and longer-term, he said, the company intends to build its own leaseholds through participating in lease sales.

The name Venari stems from a Latin verb that means “to hunt.” On Tuesday, the startup announced $1.125 billion US in funding from a consortium of private equity firms that includes Warburg Pincus, Kelso & Company, Temasek, and The Jordan Company. Part of the business plan is to consider going public, Reinsborough said.

The former president and chief executive of Nexen subsidiary Nexen Petroleum U.S.A. Inc. said Warburg Pincus scouted him to develop an exploration and production company anywhere in the world and gave him a blank canvas. The core management team at Venari, which now employs 16, assembled earlier this year from a group that has worked together since 2000 at Nexen.

Reinsborough zeroed in on the Gulf of Mexico, citing a unique business climate post-moratorium, “very high netback barrels” in the Gulf — an industry measure of the returns on produced oil — a transparent fiscal regime in the region, proximity to market and a safe operating environment.

“I had had a lot of success building a program there in my previous life at Nexen and we wanted to replicate it.”

Reinsborough wouldn’t disclose why he left Nexen following 17 years at the company, 15 of those spent developing the deepwater Gulf of Mexico program.

Around the same time as his departure last July, Nexen announced it had restarted exploration drilling in the Gulf with a first well, Kakuna — a well it began abandoning earlier this month with partners Statoil ASA and Chinese state-owned CNOOC Ltd.

Nexen, as operator, spent $120 million on the sub-salt Kakuna well and did not encounter enough oil or gas to warrant commercial development, the company said.

The Calgary oil and gas explorer, with partner-operator Royal Dutch Shell PLC, is evaluating a possible 2014 sanction of development of Appomattox, a deepwater Gulf of Mexico field estimated to contain 65 million barrels of oil equivalent of probable light oil reserves, net to Nexen, according to the firm’s website, and also has a joint venture with CNOOC inked last November to drill up to six deepwater exploration wells, including Kakuna.

Leta Smith, a Houston-based director of oil and gas supply at energy consultancy IHS CERA, said she’s optimistic drilling in the Gulf of Mexico will return to pre-Macondo levels but said there’s still a ways to go.

In the four months before the spill, about 13 exploration wells were drilled per month in the Gulf, she said. Twelve wells were spudded last December, following a ramp-up in activity throughout 2011, but drilling dropped earlier this year to average six wells in the first three months, Smith said.

“If you go by those new wells being spudded, I would say it’s probably not quite back there yet,” she said.

Smith co-authored a report for IHS CERA last July that suggested a return to drilling activity in the Gulf to pre-Macondo levels would add $44 billion US to U.S. gross domestic product and support nearly 230,000 jobs.

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Baker Hughes Inc (BHI.N) believes the U.S. oil-directed rig count would have to double to more than 2,500 rigs if analyst estimates of a 2 million-barrel-per-day increase in U.S. oil production by 2017 are correct.

Chief Financial Officer Peter Ragauss said this rapid shift to oil production, which has caused severe short-term disruptions to the U.S. market this year, would ultimately favor Baker Hughes because of its technology.

The move out of natural gas areas to those rich in liquids has squeezed pricing for hydraulic fracturing services, but stronger pricing elsewhere was expected to offset that.

“Frack pricing is declining in the gassy basins, but on the flipside the volumes are declining in the gassy basins, so it has less impact,” Ragauss told the UBS Global Oil and Gas Conference in Austin, Texas, adding that Baker’s fleet utilization was increasing every month as it settles in to new places.

Baker Hughes is also increasing capacity in the Bakken and Permian basins, which are both driving the U.S. oil boom.

As for some key ingredients used in fracking, Ragauss said the price of guar had flattened after steadily rising for months. While finer grain sand was in plentiful supply, Baker was not getting much price relief because the market for coarser sand remained tight.

“You’re spending more on freight than you are on the actual commodity,” Ragauss said of the sand. “I wouldn’t expect a big (pricing) drop in any of those commodities.”

Ragauss said the Gulf of Mexico was steadily improving as drillers return in droves, but that would mean more to Baker Hughes in 2013 when more wells were being completed.

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Think of the oil and gas markets as a two-person play in which the actors have suddenly swapped costumes.

Over the past four weeks, the price of West Texas Intermediate, the North American benchmark oil price, has declined 15 per cent. But in a remarkable plot twist, natural gas (at Henry hub) has gained 42 per cent. The latter has donned a set of bull horns it hasn’t worn in more than a year, while oil is now clad in brown fur.

Why oil remains key to the economy

We’ll be watching this developing scene with interest – it’s a complicated plot. But North American investors should know something interesting about this play: Both actors can’t dress up as bears.

Pundits have been quick to blame oil’s bearish retreat on economic woes, starting with the never-ending debt situation in Europe. But the plotlines connecting Athens and Madrid to oil centres like Riyadh, Houston and Edmonton are thin. Europe’s economy and its oil (CL-FT90.850.951.06%) consumption have not been correlated for years, so why should oil prices be falling on the euro zone’s troubles?

But there is a tangled thread lurking in the script: If westerners are unemployed, they can’t buy as much stuff from China, which means the Chinese economy loses momentum, which means fewer people in Beijing are able to afford a gas-guzzling car – which, ultimately, means global oil prices turn bearish.

Europe, in fact, is far less important here than China, because half of all new oil consumption emanates from the Asian giant. Yet the sketchy numbers that track China’s economy have been slowing recently and it’s noteworthy that global oil demand has not expanded much in the past year. Overall growth on 89.5 million barrels a day is now tracking less than 1 million barrels a day. Except for 2009, the year of the financial crisis, it has been many years since world oil consumption grew by less than 1 million barrels a day.

This tepid global appetite, combined with momentum on the supply side, is contributing to oil’s newly bearish character.

At the same time, natural gas (NG-FT2.73-0.01-0.44%) has surprised the audience. A 35-per-cent jump in demand from power generators, combined with stagnant production from U.S. gas fields, is helping to burn off the staggering 800 billion cubic feet of surplus storage that accumulated over the past warm winter. Eager market participants are not waiting for that to process to run its course, however. Benchmark U.S. prices have already risen, from $1.90 to $2.70 per thousand cubic feet in one month. Other positive leading indicators, such as declining rig counts, contribute further to natural gas’s newly bullish role.

The most intriguing part of this play is that a bearish oil price performance reinforces a bullish price trend for natural gas. That’s because natural gas is produced from oil wells too.

Indeed, one of the principal reasons for the steep drop in natural gas prices in recent years has been “associated gas,” or gas that bubbles up when pumping oil. As the number of oil rigs has risen in North America – from 200 to 1,600 in three years – there has been a surge in associated gas production. It was up 2 billion cubic feet per day in 2011. An additional 3 Bcf/d is expected in 2012. Right now, the U.S. produces 9.0 Bcf/d in associated gas, which represents 12 per cent of North American production. Without associated gas, overall continental natural gas production would decline – triggering higher prices.

So it’s important to realize that weaker oil prices, if sustained, will tend to dampen the zeal for aggressive oil drilling, thus reducing natural gas production.

The plot is indeed complicated, but all you need to know is that there is only one bear suit possible: If you are bearish on oil, you have to be bullish on gas.

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Natural gas futures ended higher on Wednesday for a second straight day, as tighter supply-demand fundamentals and forecasts for warm weather offset early selling on the milder outlook for late next week.

Gas prices, which rallied 9 percent last week, are nearly flat so far this week, with investors cautious about prices near 3-1/2 month highs ahead of a three-day weekend.

NYMEX floor trading will be closed on Monday for the U.S. Memorial Day holiday.

Since posting a 10-year low of $1.90 per million British thermal units in April, nearby futures are up nearly 44 percent amid signs that record production was finally slowing while demand was picking up as more electric utilities switch from coal to cheaper gas for power generation.

Technical traders had been expecting Monday’s 5 percent pullback, noting the front-month contract shot into overbought territory late last week as it peaked on Friday at a 3-1/2 month high of $2.759 per million British thermal units.

But they noted prices seemed stuck just below resistance in the $2.75 area.

Front-month gas futures on the New York Mercantile Exchange ended up 3 cents, or 1.1 percent, at $2.737 per mmBtu after trading between $2.615 and $2.747.

Stronger gains in the front contract continued to narrow spreads to winter months, with the December premium to June ending Wednesday at 66.1 cents, down 4.4 cents from Tuesday and 33 percent below its peak this year of 99.3 cents hit just six weeks ago.

“We’re in an uptrend, but the market seems hesitant to break above $2.75 until we see the storage report tomorrow. I think we need another supportive number (light weekly build) to go any higher,” said Steve Mosley at SMC Advisory Services in Arkansas.

Some traders remained skeptical of the upside with storage and production still at or near all-time highs and prices reaching levels that could slow or even reverse utility fuel switching, a big factor in boosting gas demand this year.

STORAGE STILL AT RECORD HIGHS

U.S. Energy Information Administration data last Thursday showed gas inventories for the week ended May 11 rose by 61 billion cubic feet to 2.667 trillion cubic feet.

Weekly inventory builds have fallen below average in five of the last six weeks and are likely to do so again in Thursday’s report, with traders and analysts polled by Reuters expecting stocks to have gained 76 bcf last week.

Storage rose an adjusted 101 bcf during the same week last year. The five-year average increase for that week is 97 bcf.

Lagging stock builds this spring have raised expectations that record storage can be trimmed to more manageable levels in the 180 days or so left before winter withdrawals begin.

A huge storage surplus to last year — at 774 bcf or 41 percent — is down 13 percent from late-March highs, but there are still concerns that the glut could drive prices lower again this summer as storage caverns fill to near capacity. (Storage graphic: link.reuters.com/mup44s)

The storage surplus to last year will have to be cut by another 525 bcf to avoid breaching the government’s 4.1-tcf estimate of capacity. Stocks peaked last year in November at a record high of 3.852 tcf.

PRODUCTION NEAR RECORD

Despite declines in dry gas drilling and planned output cuts by several key producers, gas production, primarily from shale, is flowing at near-record highs.

Announced cuts so far have probably slowed output by less than 1 bcf per day, or just a little over 1 percent, not enough to make a real dent in a seriously oversupplied gas market.

Baker Hughes data on Friday showed the gas-directed rig count was hovering just above 10-year lows at about 600.

The count is down 36 percent since peaking at 936 in October and has stirred talk that producers were finally getting serious about stemming the flood of supplies.

But Baker Hughes data also showed that horizontal rigs, the type most often used to extract oil or gas from shale, hit another all-time high last week.

The shift away from dry gas to higher-value shale oil and shale gas liquid plays still produces plenty of associated gas that ends up in the market after processing. That has slowed the overall drop in dry gas output.

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