The shift to the wet-gas window of shale plays and the pursuit of natural gas liquids will continue even if oil prices slump and/or an NGL production glut occurs, says a new report from Barclays Capital gas and power analysts Biliana Pehlivanova and Michael Zenker.

U.S. natural gas production has risen 11% in the past two years, but associated NGL production is up 15% in the same period, says Barclays. New plays targeting NGLs are emerging in the U.S. and Canada, joining more established plays such as the Eagle Ford and Marcellus shales.

"Drilling dry gas is so 2009," according to the report. That's because NGLs from wet-gas wells fetch higher prices than natural gas at the moment. Gas prices would have to rise by "several dollars" for a dry-gas well to meet or exceed the return from a liquids-rich well, according to Bar-clays.

NGL prices are often quoted in percent-of-oil terms, and in July were running about 57% of the price of West Texas Intermediate crude. Will the shift to liquids-rich plays continue if oil prices slide?

The Barclays analysts tested two worst-case scenarios—a drop in NGLs prices relative to oil and a low-oil-price case of $60 per barrel (although Barclays is not forecasting that price). In both scenarios, "while the attractiveness of liquids-rich wells fades, they remain superior investments to dry-gas drilling.

"That is, NGL drilling, as well as the continued growth in gas supply from this subset of wells, is likely to continue."

Liquids-rich plays have attracted so much drilling attention that investors have asked, what if an NGL glut occurs? Barclays ran a number of scenarios and concluded that "a drop in oil or NGL prices is unlikely to stall liquids-targeted drilling, and the natural gas that these wells produce should remain a growing component of supply."

—Leslie Haines

For complete coverage of liquids-rich plays, see UGcenter.com.

Can the numbers get any better for pressure pumpers?

After a better-than-expected second-quarter performance in North America, the Big Four—Baker Hughes, Halliburton Inc., Schlumberger Ltd. and Weatherford Inc.—are convinced that margins, particularly for well-stimulation services, are going to top the 2008 peak. Forget weakening commodity prices, forget rapidly expanding pressure-pumping capacity, forget troubles in North Africa, the European economic theater, or the U.S. stock market. Lastly, forget that customers, who are now price-takers, are raising capex at a greater pace than production forecasts in the face of falling energy prices, signaling the advent of a customer margin squeeze.

The current story line for the Big Four goes as follows: There are no worries about the North American pressure-pumping market, despite significant capacity expansion, which is looking good into 2013. The international arena is on the verge of picking up, characterized initially by rising revenues and, ultimately, by expanding margins. And, the offshore arena is waking up after its long Macondo nap, though startup costs are a short-term hit to margins.

That's not to say everything was smooth for the Big Four, even as they easily beat consensus projections for the second quarter. A long, hard Canadian break-up impacted North American revenues for all, while start-up costs in the Gulf of Mexico ate away at margin.

The four companies report early in the earnings season each quarter, and generally set the industry tone. This quarter, all managed to report before the global stock market collapse during the first week in August and the coincident contraction in oil prices.

The easy take-away is that diversified services are the place to be at this point in the oil and gas cycle. As a whole, profitability, when measured as operating income for the group in aggregate, is rising. Collectively, operating income grew globally, from 13% in the second quarter of 2010 for the Big Four to 16.3% currently, but was on par with fourth-quarter 2010, when a sudden rush among customers to acquire seismic at year-end provided a revenue boost for some diversified firms.

Secondly, the strong operating margins reported were regional in nature and weighted to North America, where operating income for the four companies grew from 15.2% collectively one year ago to 23.5% currently, though the rate of growth in operating margin slowed in the last three quarters. This compares to their overall global operating margin, which grew from 13% one year ago to 16.3% during the second quarter.

The group generated $23.3 billion globally in revenues for second-quarter 2011, a 24% increase on a year-over-year basis—and a bullish 9% sequentially.

The diversified firms most tied to North America include Baker Hughes, which has seen North America generate 50% (or more) of its revenue stream during the past three quarters, and Halliburton, which has witnessed its North American revenues rise from 48% of sales one year ago to 58% currently, after a nice run during the first half.

Companies tied least to North American markets in terms of overall revenue generation include Schlumberger, which derives a mere 30% of its revenues from North America, and Weatherford, which saw North America peak at 48% of its revenue stream in the first quarter of 2011 before dropping back to 44% in the second quarter, a result more consistent with its historical trend line.

In all, the Big Four recognized $10 billion in revenues out of North America during second-quarter 2011, with Halliburton representing 34% of the total, followed by Schlumberger at 29%, Baker Hughes at 24%, and Weatherford a distant fourth at 13%.

Demand for pressure-pumping services to exploit tight formation oil and gas is the major driver in North American revenue growth for these diversified service firms. Within North America, the gross operating margin was highest for Halliburton at 29%, followed by Schlumberger at 23%, with Baker Hughes and Weatherford generating a margin of 19% and 18%, respectively.

Of the $2.35 billion in operating margin reported collectively for North America, Halliburton accounted for 42% of the total followed by Schlumberger at 29%. That means the Big Four are really the Big Two when it comes to profitability in North America.

But the main story during the second-quarter conference calls involved future revenue opportunities, as North America transitions to tight-formation oil and gas. Collectively, the Big Four saw second-quarter 2011 North American revenues jump 49% to $10 billion on a year-over-year basis, while rising 8% sequentially. Operating income, however, vaulted 130% year-over-year to $2.34 billion and rose 14% sequentially.

Looked at another way, the North American revenues for the Big Four rose from a 36% share of global totals one year ago to 43% in second-quarter 2011, while operating income soared from 42% one year ago to 62% currently.

While business has improved across all product lines, the driver for growth among the diversified service firms is associated with pressure pumping services. Spears & Associates Inc. analyst Richard Spears has compiled gross dollar figures during the last six years for offshore drilling and pressure pumping, which are two of the three largest sectors in oil and gas. Pressure pumping traditionally ran third in a triumvirate that includes offshore construction.

But the industry is undergoing structural changes. Pressure pumping represented $25 billion in revenues in 2010, compared to $36 billion in offshore drilling. For 2011, Spears projects pressure pumping will top $38 billion, while offshore drilling comes in at roughly $34 billion.

Halliburton, Schlumberger and Baker Hughes represent 45% of North American market share by frac hydraulic horsepower (HHP). Spears projects North American capacity will grow from 9.9 million HHP in 2010 to 14 million in 2011.

—Richard Mason

Carrizo leads 15-E&P pack in exposure to Niobrara in D-J Basin

Small-cap E&P Carrizo Oil & Gas Inc. may have the greatest potential for Niobrara oil potential from the Denver-Julesburg Basin relative to its size, say Tudor, Pickering, Holt & Co. Securities Inc. analysts in a new report on the Rockies play.

The study, led by Jessica Chapman, includes an evaluation of 15 E&Ps with Niobrara acreage, among the 36 U.S.-focused producers the team covers. The analysts looked at potential impact the acreage location of each may have on net asset value and daily production.

"Productivity of the Niobrara is highly variable, thus, it is not a blanket 'resource play,'" Chapman says. "Instead, we believe smaller, productive 'fields' within the play will develop."

Resource plays include the Bakken, where output is fairly consistent across the formation, and, once the code is cracked on well spacing and fracture stimulation, roughly the same science is applied from well to well.

It isn't this simple to produce from Niobrara. "In the Niobrara, there is still geologic, drilling and completion risk across the play," Chapman says. "The likelihood of a 'silver bullet' completion is low, and completions will look different from one part of the play to another."

Most of Carrizo's D-J Basin acreage is in the Colorado Mineral Belt extension that is north of Wattenberg Field and is one of five areas the TPH analysts examined for productive potential. There, the rock is more "cooked" or has greater thermal maturity, and it has areas of higher pressure. "We expect this is prime real estate for economic Niobrara production, with adequate thermal maturity, medium gas-oil ratio (GOR)—or reservoir energy—and high resistivity."

Carrizo's work on its 62,000-net-acre leasehold may grow its production there more than 200% in 2012 and an average of more than 100% a year from 2012 to 2015, Chapman forecasts.

Also having significant exposure to this window is EOG Resources Inc. Four other play windows in the D-J Basin are Wattenberg Field, Silo Field, the Colorado-Wyoming border and an "other D-J Basin areas" category.

In Wattenberg Field, Anadarko Petroleum Corp., Noble Energy Corp. and Petroleum Development Corp. have the most exposure. There, the GOR is high toward the center of the field, Chapman says, and oilier at the fringes. "It is relatively over-pressured, allowing for matrix production." A large number of vertical wells have been drilled in this area already, so a key in landing wells will be to avoid depleted zones, she adds.

At Silo Field, SM Energy Co. has the most exposure relative to its size. There, GOR is low to medium, pressure is normal and there is a great deal of natural fracturing. The opportunity in this area includes recompleting existing wells, and matrix production might be possible.

At the Colorado/Wyoming border, where Anadarko, Noble and EOG have the most exposure, Chapman expects economic Niobrara matrix production, as there is adequate thermal maturity, a medium GOR and also high resistivity.

Elsewhere in the D-J Basin, the nature of the rock varies, she says. There is lower overall pressure, thermal maturity and GOR. It will be more difficult to systematically produce oil here, and operators may have to rely on the natural fractures.

"The best acreage has high resistivity, adequate thermal maturity, enough reservoir energy to mobilize the oil—via reservoir pressure and natural gas in situ—and natural fracturing," Chapman reports.

Besides Carrizo, other Niobrara favorites, based on acreage location and exposure relative to the company's size, are Anadarko and Noble. "We expect Anadarko's Niobrara production in the D-J Basin to grow an average 10% a year thru 2015," Chapman says. The forecast does not include Anadarko's exposure to Niobrara potential in the Powder River Basin, she adds.

For Noble, the TPH team expects daily Niobrara production from the D-J Basin to nearly double to some 100,000 BOE by 2015.

As investors have noticed from well results, the Niobrara is unpredictable, compared with the Bakken. "Smaller, localized or field-level developments are likely with blanket 'acreage math' much less likely to work across big acreage positions," Chapman says.

Essential to developing the play will be the use of seismic and geo-steering to stay in zone. Completion methods will vary, and artificial lift will be necessary in Niobrara wells' early years.

—Nissa Darbonne

For more on the Niobrara, see the June 2011 cover story of Oil and Gas Investor, and UGcenter.com.

Global Hunter: Onshore natural gas production slows dramatically

Growth in onshore natural gas production in the contiguous U.S. (Lower 48) has slowed dramatically, inching up just 0.2% in May to 63.9 billion cubic feet per day (Bcf/d), according to a Global Hunter Securities analysis.

In the report, released August 3, Global Hunter E&P analysts said that since October 2010, the firm's modeling has suggested that domestic onshore production would plateau or peak around this time, setting the stage for potentially flat or even declining results in the coming months.

The plateau is supported by second-quarter 2011 production reported by public producers, down 1% sequentially and flat year-over-year, according to the report. Majors thus far have reported natural gas production down 2% sequentially, similar to results from large-cap independents. Mid-cap and small-cap producers reported growth of 1% and 12%, respectively.

"While we don't forecast a screaming decline in natural gas production going forward, especially with the Marcellus monster lurking behind infrastructure build-out in Appalachia, the stage is set for demand growth to outpace supply growth for the back half of the year, which should be more supportive for prices," said lead analyst Dan Morrison.

"The growth baton is currently being passed from the Haynesville to the Marcellus. How the timing of the slowdown in the Haynesville and the ramp up in the Marcellus coincide will be the biggest determinant in the natural gas production profile going forward." According to data from the most recent EIA-914 survey, a monthly report that collects natural gas production volume information from a sampling of well operators, Louisiana production, while still growing, appears to be decelerating.

"With Chesapeake's recently announced rig-count reduction in the Haynesville, the days of meteoric production growth from Louisiana should be behind us," Morrison said.

—Mike Madere

Post-recession, Texas' E&P job market bounces back

Thanks to an 18-month-long expansion of the Texas oil and gas economy, tracked by the Texas Petro Index (TPI), petroleum industry employment has surpassed a 2008 milestone and helped create about two-thirds of all jobs added in the state during the past year.

"Post-recession job growth in Texas has been among the strongest in the nation, and the oil and gas industry in Texas deserves most of the credit for that," said Karr Ingham, the economist who created the TPI and updates it monthly.

Unemployment was 8.2% in Texas in June. Nationally, the unemployment rate is about 9.2%.

According to the TPI, which tracks growth rates and business cycles in Texas' upstream energy economy, total oil and gas industry employment in Texas in June reached 224,200, a gain of almost 15% since June 2010. The June 2011 figure marked the first time more Texans have been working in the state's oil and gas industry than in October 2008 (the previous peak, when Texas Workforce Commission estimates pegged the count at 223,200).

"In the past 12 months, the industry has added more than 28,600 jobs, nearly 13% of all jobs added to the Texas economy," Ingham said. "That's really an accomplishment, considering the TPI in June indicates the industry still has not recovered to the level of economic health that created the last jobs milestone.

"More importantly, when a conservative multiplier of 5.0 is used to model the direct, indirect, and induced effects of petroleum industry employment on the statewide economy, one discovers that industry activity accounted for a whopping 66% of total job growth in Texas during the past 12 months."

A composite index based upon a comprehensive group of upstream economic indicators, the TPI increased in June for the 18th consecutive month to 243.5, from a low in December 2009 of 186.6. The TPI peaked at 286.0 in September and October 2008. There are typically three distinct cycle periods in the index's history: a period of growth, followed by decline, then recovery.

So far in 2011, Ingham said the index is continuing its "unfettered run." However, the June TPI figure is still about 40 points below its peak, and it could take a year or more to reach the 2008 high.

During Ingham's presentation of the latest TPI results in Houston in late July, he also commented on the major integrated companies' recent interest in putting down unconventional roots.

"When the big boys come back into a play, it signals a play's longevity, and it's good news for Texas and the nation. While independents want what they can produce in a shorter period of time, larger companies can afford to take on projects that have longer horizons."

He was also positive in his outlook for oil. "E&P companies drilled so much during the past few years and they found large amounts of gas. I'm convinced the industry could go a long way and provide a similar outcome for oil."

As for gas, he said it will be a while before we reach the Texas production peaks of 2009 without some improvements in natural gas pricing. "Natural gas production is a sad tale in Texas, but it's the result of its own success. But, don't forget how the markets work. Increased production leads to reduced demand. A reverse of this should bring gas prices back up, but we can't be sure when this will happen.

"Nevertheless, the long-term future for natural gas is extremely bright, which means the outlook for E&P gas activity is bright. For now, Texas E&Ps are returning to their oily roots."

Among leading TPI indicators during June:

Crude oil production in Texas totaled an estimated 34.1 million barrels, 0.4% more than in June 2010. Crude production in the first six months of 2011 totaled nearly 211 million barrels, an estimated 3.5% increase.

The value of Texas-produced oil was nearly $3.16 billion, 29.5% more than in June 2010. The value of Texas crude produced during the first six months of 2011 totaled more than $20 billion, up 31.3% compared to the first six months of 2010.

Estimated Texas natural gas output was nearly 576.5 billion cubic feet, a year-over-year monthly decline of about 6.1%. Texas operators in first-half 2011 produced more than 3.47 billion cubic feet of gas, down about 6.5%.

The value of Texas-produced gas totaled $2.46 billion, about 0.2% more than in June 2010. The value of gas produced by Texas operators in first-half 2011 totaled nearly $14.4 billion, a decline of more than 17%.

The Baker Hughes count of active drilling rigs in Texas averaged 839, 26.5% more than in June 2010, when 663 rigs were active on average. The number of drilling rigs working in Texas during first-half 2011 averaged 780. Drilling activity in Texas peaked in September 2008 at a monthly average of 946 rigs before falling to a trough of 329 in June 2009.

—Bertie Taylor

Midstream evolving into attractive target for investors

The midstream sector, which has historically received less investor interest than E&P and oilfield services, is in the middle of an unprecedented transformation brought about by a revolution in North American unconventional-resource development, according to a study by Houston-based Tudor, Pickering, Holt & Co. Securities Inc. "Forget what you thought you knew about midstream," says Bradley Olsen, the company's vice president of midstream research and lead analyst of the report, which was released in early July.

"This is not the interest-rate-exposed, commodity-neutral 'toll road' sector you have been told about. During the last five to 10 years, it's shown increasing correlation with crude, declining correlation with gas and less sensitivity to interest rates."

And, he contends, the midstream has become a formidable target for investors. "Capex dollars, M&A activity and historically low yields indicate that the North American midstream is sharing in the unconventional-resource boom. As a result, midstream companies are leveraging existing assets and securing long-term commitments on previously under-utilized infrastructure, and we want in."

The U.S. is producing wetter, less-expensive hydrocarbons than it did just a few years ago, according to the study. In addition to revitalizing domestic production, unconventional-resource growth is challenging the existing energy infrastructure, which has been geared toward Gulf Coast gas production and crude imports from Canada and overseas. A massive industry-wide capex build-out has begun as North America grapples with a coming wave of crude and natural gas production.

A shift from dry-gas Btus to wet-gas Btus has been under way for the past 18 months, according to the analysis, which expects midstream growth to primarily come from liquids supply.

"We believe that NGL volumes could increase by 700,000 barrels per day by 2015, roughly 25% higher than current levels. This includes product declines in the Gulf of Mexico and mature onshore basins, requiring construction of nearly 1 million barrels per day of pipe capacity," Olsen says.

"This tectonic shift in the composition of U.S. hydrocarbon production presents midstream opportunities through the value chain, from upstream (gathering, trucking processing, storage terminals) to downstream (pipelines, fractionation, storage)."

Crude oil/condensate growth will come from Canada, the Bakken, the Eagle Ford and the Permian Basin, while NGL growth will come from the Eagle Ford, Granite Wash and Permian, the study projects.

Liquids growth through 2017 has the potential to be big, the analysts note. Among the report's projections are a hike in Permian Basin NGL production of more than 200,000 barrels per day by 2015.

Midstream providers are positioned to benefit from volume growth from the wellhead to the downstream delivery point. The midstream sector has not had a similarly target-rich environment in its relatively brief history as a stand-alone sector.

The wave of growth will not fuel a 2007-2008-style boom, when creeping commodity leverage drove rapid growth followed by a cash-flow collapse for some midstream companies.

The analysis provides handicaps for the possibility of new pipelines out of the Cushing, Oklahoma, hub: The XL Pipeline, a 1,980 mile-long project with the capacity to carry up to 900,000 barrels a day, will almost certainly be built. The pipeline project is currently undergoing a review process by the U.S. Department of State. Given the political climate, it is difficult to predict when the pipeline will be built; most likely, in 2013 or 2014.

Enterprise Products Partners LP and Energy Transfer Partners LP have announced a joint venture, the Double E Pipeline, which would run from Cushing to the Gulf Coast. The likelihood of the project coming to fruition is "high," according to the study. The pipeline could be in service by the end of 2012.

Enbridge Inc.'s Monarch project has been on-again, off-again for the past several years. Despite Enbridge indicating in January 2011 that it was close to receiving an anchor-shipper commitment needed to make it economically viable, Monarch remains unlikely if the XL and Double E are built.

The "unconventional-resource revolution," has transformed the North American gas market, note the analysts.

"Even as the U.S. has not yet figured out how to fully capitalize on our novel position as a low-cost energy supplier—as evidenced by overflowing gas storage, shale moratoria and other head-scratchers—the changes it has brought and will bring to our economy are profound," Olsen said. "We believe that the true game-changing opportunity for the midstream industry is the price dislocation between wet and dry Btus of energy."

Because oil and gas are not directly fungible, a price disparity exists. However, the study contends that there are ways to substitute lower-cost gas byproducts for high-cost gas byproducts, effectively increasing the demand for wet gas.

Ethylene, the most widely produced plastic feedstock, can be produced from ethane, propane or crude byproducts such as naphtha and gas oil, allowing petrochemical companies to exploit the low price of gas.

Propane has transportation and heating applications. The U.S. was once an importer of propane but is now an exporter, taking advantage of a demand in developing markets that are transitioning from open-flame heating and cooking.

Cheap natural gas is driving the obsolescence of residual fuel power generation in certain U.S. markets, primarily the East Coast.

Among plays in the continental U.S., the analysts noted a number of developing trends. The Marcellus competitive environment is more fluid than the Eagle Ford, Granite Wash and Permian Basin, with less dominant midstream players and more opportunities for M&A. The Eagle Ford has emerging gathering and processing bottlenecks because the pace of drilling is exceeding that of pipe-laying.

Bottlenecks are also a factor in the D-J Basin, and Shell's recent announcement to build a Marcellus-area cracker will prevent Marcellus ethane from reaching the Gulf Coast or being blended into pipelines over the long term.

And finally, the study foresees that more liquid petroleum gas (LPG) from the U.S. will be consumed overseas.

"Potential fractionation overbuild will likely put some pres- sure on ethane. Longer term, we think ethane is going to have an advantage as a petrochemical feedstock due to North American shale-gas supplies," Olsen said. "Other products should weather ethane oversupply due to the industry's growing ability to export LPGs (propane and butane)."

—Mike Madere

For more midstream news, see midstreambusiness.com.

Study your rocks, data in shale plays; assume nothing

Economic variability within shale plays is something crucial that a lot of people miss. Even in the so-called sweet spots of a given play, geology and technical factors matter. Every well will not produce the same results and every well will not necessarily resemble the best well.

"You have to recognize this going in," Danny Simmons, chief operating officer of engineering consulting firm Netherland, Sewell & Associates Inc., told members of the Houston Energy Finance Group recently. "You can't just 'broad-brush' this and say a shale play has to have certain spacing. It takes a lot of data to determine that."

As technology continues to improve over time, well results will change. Early in a play's development, proved-reserve numbers go up as more wells are drilled and operators come to understand the geology better, and perfect their completion techniques.

"P2 reserves are the number most people look at when making decisions, but that number may not increase, or may stay about the same. You need to look at estimated ultimate recoveries (EURs) versus well spacing and EURs versus the economics" of a play.

"You can't generalize and extrapolate a certain number over an entire play. You have to look hard at your specific acreage."

Simmons said he suspects some companies are trying to make their acreage economic by doing what it takes to get the highest return early, versus trying to produce the most oil or gas the reservoir can yield in a sustainable fashion.

He advised operators to spend enough money and time early in a play's life-cycle to get plenty of data, figure out the optimum length of the horizontal leg of wells, the right number of frac stages, frac fluids and the frac intensity. Operators also must look at core data, free gas versus adsorbed gas, matrix porosity, storage capacity (gas in place) and flow capacity, among many other factors.

Simmons cited the fact that the Barnett shale was slow to develop at first and early on the economics were very tough. He showed a plot of northeast Wise County and an average EUR of 1.5 billion cubic feet of gas, but the actual wells range widely around that number, with wells on the flank being uneconomic.

"You pretty much have to be in the good areas—and then do the right thing once you are there," he said, and that is only possible by analyzing as much technical data as possible.

The proof is in the pudding: The average EUR in the Eagle Ford was 1 billion cubic feet equivalent before 2009, but as much as 5.7 billion in 2010.

—Leslie Haines

For more on the economics of the shales, see OilandGasInvestor.com.

McClendon: Eyeing the next lineup of liquids-rich plays

Chesapeake Energy Corp. remains one of the largest producers in North American natural gas and liquids production, with significant holdings in the most prolific basins on the continent. And, the company continues to eye liquids plays for the future: the Mississippi Lime in northern Oklahoma and southern Kansas, the Cleveland and Tonkawa tight sands in the Anadarko Basin and the Utica shale in eastern Ohio.

Although Chesapeake discovered the Mississippi Lime in April 2007, it has been slow to develop the play because it was discovered at the same time as the Colony Granite Wash, notes chairman and chief executive Aubrey McClendon.

"Because we were unsure of the ultimate size of the Mississippi Lime play and unsure of how predictable the rocks would be, we ended up developing our Granite Wash assets more quickly.

"However, in the past year, it has become more clear that we have a major play on our hands in the Mississippi Lime and so we ramped up our leasing and drilling efforts quite significantly," he said during a conference call to discuss second-quarter 2011 earnings.

Chesapeake now owns the most acreage in the play at 1.1 million net acres and is using six rigs to develop leaseholds. McClendon anticipates this rig count will increase to 10 by the end of the year and reach 30 to 40 rigs by the end of 2014 or early 2015.

"To date, we have drilled 56 Mississippi Lime horizontal wells and have found an average of 415,000 barrels of oil equivalent per well at an average finding cost to date of approximately $11 per barrel. Obviously very, very attractive results to date," he said.

In the years to come, Chesapeake will drill up to 6,750 net wells in the play for a roughly 2.2 billion barrels of unrisked oil equivalent impact to the company.

Chesapeake will seek to monetize its assets in the play by seeking a joint-venture partner in the first half of next year, McClendon said.

The company has been able to undertake such JVs due to its large holdings in North American unconventional plays. This stance is also the case in the Cleveland and Tonkawa tight-sands plays.

"One reason that you've not heard too much about these plays is that Chesapeake's 720,000-netacre leasehold position across these plays is so dominant that no other public E&P company has been able to build a meaningful competing interest and talk up the play," McClendon said.

This dominance derives from the company's history in the Anadarko, where it has built the largest holding from 2001 to 2007 as part of its "long on natural gas" strategy.

"Because of this unmatched leasehold position in the Anadarko Basin, Chesapeake possesses unique informational and operational advantages which have enabled us to discover several large new plays in the region. The Anadarko Basin is today one of the two premier liquids-focused basins in the U.S. with the Permian Basin being the other," he said.

To date the company has drilled 116 horizontal wells in the Cleveland and Tonkawa plays combined with gross estimated pro forma reserves of approximately 600,000 barrels of oil equivalent per well and finding and development costs of approximately $12 per barrel. The company has 16 rigs combined in the two plays and anticipates increasing this to 25 to 30 rigs throughout the next few years.

The newest of the four liquids-rich plays is the Utica shale in eastern Ohio. McClendon envisions it will be more important to the company than its other major unconventional discoveries of the past four years.

"In some respects, the play reminds us of the Haynesville shale, in the fact that we worked undercover for more than a year to develop the basic geological and petrophysical model. We built the largest leasehold position in the play and then drilled the first discovery wells. This is certainly also the case with the Utica, where we started working on the play 18 months ago, started buying leases shortly thereafter and today quietly and efficiently have built the largest leasehold position…," he said.

The Utica's economics are similar, and likely, superior, to the Eagle Ford, he said. "The similarity is that we expect the Utica to have three phases—a dry-gas phase on the eastern side of the play, a wet phase in the middle and an oil phase on the western side. The difference is we believe the Utica will be economically superior to the Eagle Ford because of the quality of the rock and the location of the asset."

McClendon declined to discuss the company's IP rates or reserve estimates, but he noted that based on the nine vertical wells, six horizontal wells and 3,200 feet of proprietary core the company has analyzed, it believes its 1.25 million net acres in the Utica will be worth $15 billion to $20 billion to the company's shareholders through a future monetization effort.

"I might also add that in the Utica as in the Mississippi Lime, we have been approached with a number of alternative monetization ideas that we believe will be quite competitive with the standard industry JV process," he said.

—Frank Nieto

E&Y: Oil prices, demand look strong for third quarter

Oil prices and demand should continue to increase in the third quarter of 2011, even with ongoing uncertainty about the economic recovery, deficit-reduction initiatives in the U.S. and the debt crisis in Europe, according to a report by analysts at Ernst & Young LLP.

A bright spot in the oil outlook is the increasing activity in the Gulf of Mexico since the Deepwater Horizon oil spill last year. Overall production remains below pre-2010 levels, but the applica- tion and permitting process has picked up substantially, according to the August 3 report.

Oil production elsewhere in the Americas continued to increase as well, notably from the Bakken formation, as well as from the Canadian oil sands and Brazil.

The "big unknowns " for oil producers are the short-term effects of the International Energy Agency's release of 60 million barrels from emergency supplies and a disagreement among OPEC members about supply increases. The IEA's announcement, which was triggered by a disruption of supply from Libya, brought a temporary decline in oil prices. However, as the market moves into the high-demand season, the IEA release will not meet increased demand, the report said, and the market will need more supply from OPEC at a time when its spare capacity is at its lowest level in more than 20 years.

"Oil prices are dictated by supply and demand, and all signs point to modest oil demand growth and uncertain supply," said Marcela Donadio of Ernst & Young. "Barring a strong economic shock, continued strong oil prices seem to be in order during the next three to five years."

Natural gas production in the U.S. continues to grow, with the latest production figures reaching a high point in almost 40 years. Shale gas, which is propelling the growth, is approaching about 30% of the nation's total gas production even as gas-directed drilling has slowed and issues about the economic feasibility and potential environmental impact of the resource are raised.

With softening crude prices during the second quarter, the U.S. downstream sector had a relatively strong quarter as average cracking margins moved close to $30 per barrel, according to the report. Refiners with access to the "undervalued" crude oils, such as West Texas Intermediate and Canadian crude, continued to see stronger margins than coastal refiners, which are more exposed to global crude oil markets. Investments in new refining capacity made in recent years are coming to fruition and are expected to overwhelm growth in oil demand in the short-to-medium term, bringing weakening conditions for margins during the next few years.

Oilfield service activity, which is dictated by upstream spending, is rebounding, according to Ernst & Young. Spending is expected to continue to grow by 15% to 20% in 2011, returning close to peak 2008 levels. Service capacity is being strained by the unconventionals boom, and cost increases and staffing shortages are appearing. This growth of the oilfieldservice segment is being driven by fit-for-purpose technology such as rotary steerable rigs and directional/horizontal drilling; strong oil prices; and the efficient application of shale-gas technologies such as multistage fracing and horizontal drilling.

—Mike Madere

CERA: Outlook brightens for U.S. Gulf of Mexico

With the U.S. economy in the red and debt at an all-time high, the government's clarion call should be to put more Americans back to work, according to a number of oil and gas industry groups.

Opportunities await in the U.S. Gulf of Mexico (GOM), a region brimming with potential pay, but such prospects will be stymied if permit approvals to drill in the region continue to trudge along. The permitting process now takes up to 95% longer than before last year's fatal Deepwater Horizon accident and subsequent oil spill, a new industry-funded study reveals.

What's at stake for fiscal health in the U.S. are a potential 230,000 new jobs to be created in 2012 and a $44-billion injection into the economy, in addition to increased federal and state tax revenues, according to the just-released IHS CERA report on jobs, investment and energy security. An additional $22 billion in new wages and compensation also could be realized.

These benefits would not be confined to the GOM region, however—one-third of this job creation is indirectly expected to take place in California, New York, Florida, Illinois and Georgia, according to the study.

Faster permitting could lead to an additional 400,000 barrels per day of production by 2012, the study suggests. Currently, the GOM is experiencing bottlenecks in the form of an 86% decline in the pace of regulatory approvals for plans, a 38% increase in the time to reach each regulatory approval for plans, and a 60% decline in shallow-water and deepwater drilling permits.

The group's data on the pace of permitting by the Bureau of Ocean Energy Management Regulation and Enforcement (BOEMRE) was gathered through April 30, a year after the Ma-condo blowout and six months after the federal deepwater drilling ban in the GOM was lifted.

Most telling is what the report refers to as a "growing backlog of exploration and development plan applications (currently) awaiting approval."

Specifically, a 250% increase in the backlog of deepwater plans pending approval (from an average 18 to 67 per year) is hindering an additional 1 billion barrels of oil reserves that the GOM contributes each year in the form of new discoveries, which have not been realized in the past 12 months.

The IHS CERA report was funded by the Gulf Economic Survival Team (GEST).

While the U.S. federal government restructured its offshore regulatory regime last year to streamline the processes involved in permitting, leasing, inspecting, and managing exploration on the Outer Continental Shelf, its new regulatory arm, BOEMRE, can only work as fast as its resources will allow for a quicker turnaround, Michael Bromwich, director, said in a recent hearing.

Meanwhile, several GOM discoveries and development plans have been unveiled in recent weeks, indicating a return to pre-spill activity, and BOEMRE has reported that a new Gulf lease sale is expected to occur in late 2011.

—Nancy Miller

Study: U.S. shales weakening Russian, Iranian petro-power

Rising U.S. natural gas production from shale formations has already played a critical role in weakening Russia's ability to wield an "energy weapon" against its European customers, and this trend will accelerate in the coming decades, according to a new study from the Baker Institute, "Shale Gas and U.S. National Security." The study, funded by the U.S. Department of Energy, projects that Russia's natural gas market share in Western Europe will decline to as little as 13% by 2040, down from 27% in 2009.

"The geopolitical repercussions of expanding U.S. shale gas production are going to be enormous," says Amy Myers Jaffe, the Wallace S. Wilson Fellow for Energy Studies and one of the authors of the study.

"By increasing alternative supplies to Europe in the form of liquefied natural gas (LNG) displaced from the U.S. market, the petro-power of Russia, Venezuela and Iran is faltering on the back of plentiful American natural gas supply."

The study concludes that timely development of U.S. shale gas resources will limit the need for the U.S. to import LNG for at least two to three decades, thereby reducing negative energy-related stress on the U.S. trade deficit and economy. By creating greater competition among gas suppliers in global markets, shale gas will also lower the cost to average Americans of reducing greenhouse gases as the country moves to lower carbon fuels.

The Baker Institute study dismisses the notion, recently debated in the U.S. media, that the shale-gas revolution is a transitory occurrence. The study projects that U.S. shale production will more than quadruple by 2040 from 2010 levels of more than 10 billion cubic feet per day, reaching more than 50% of total U.S. natural gas production by the 2030s. The study incorporates independent scientific and economic literature on shale costs and resources, including assessments by organizations such as the U.S. Geological Survey, the Potential Gas Committee and scholarly peer-reviewed papers of the American Association of Petroleum Geologists.

"The idea that shale gas is a flash-in-the-pan is simply incorrect," says Kenneth Medlock III, the James A. Baker III and Susan G. Baker Fellow for Energy and Resources Economics and co-author of the study.

"The geologic data on the shale resource is hard science and the innovations that have occurred in the field to make this resource accessible are nothing short of game-changing. In fact, we continue to learn as we progress in this play, and it is vital that we understand and embrace the opportune circumstances that shale resources provide. U.S. policymakers should not get diverted from the real opportunities that responsible development of our domestic shale resources present."

Other findings of the study include that U.S. shale gas will reduce competition for LNG supplies from the Middle East and thereby moderate prices and spur greater use of natural gas, an outcome with significant implications for global-environmental objectives. Also, the resource can combat the long-term potential monopoly power of a "gas OPEC."

It can also reduce U.S. and Chinese dependence on Middle East natural gas supplies, lowering the incentives for geopolitical and commercial competition between the two largest consuming countries and providing both countries with new opportunities to diversify their energy supply. And, it can reduce Iran's ability to tap energy diplomacy as a means to strengthen its regional power or to buttress its nuclear aspirations.

—Mike Madere