Bridging the gap between buyer and seller and understanding market signals are the keys to a successful deal, industry executives said at Oil and Gas Investor and A&D Watch's 10th Annual A&D Strategies and Opportunities conference, held recently in Dallas. The outlook for natural gas, and opportunities arising from lease expirations, are trends worth watching, they said.

Ken Olive, chairman and chief executive officer of The Oil and Gas Asset Clearinghouse, discussed the negotiation process. "The fact that we have seen quite a number of transaction closings in the last seven months or so is indicative that the value gap is not that great at the present time," he said. Gaps in valuation occur when price expectations diverge from what is believed to be fair.

Current market conditions generally place a ceiling on value at two times proved developed producing (PDP) assets, unless the buyer sees the asset as a strategic fit. Buyers should look at fit and consider how they could enhance production or reduce costs, rather than simply relying on what is reported in the data room.

"I've had people hang up when they were 10% away from a deal," said Olive. He noted that an acquisition that is a poor fit remains a poor fit, even at a 10% lower asking price.

While the focus has been on oil in recent years, the market may have begun to embrace dry gas as a smart play, said Sylvia Barnes, managing director and head of energy banking for Madison Williams & Co.

In July 2008, the forward curve for Henry Hub was more than $13 per thousand cubic feet (Mcf); in fact, prices plunged to as low as $1.88 per Mcf, she noted. The drop in oil after a steep incline was sharper, however, reflecting a large gap between expectation and reality.

"Ironically, yesterday (in late August) we closed around $87 (per barrel), which is pretty much where we thought we would be back in 2008,"said Barnes. She asked the audience to consider if gas was at a cyclical low and downside might be limited, and presented some interesting data points.

In the first half of 2008, gas was being valued slightly higher than oil on a barrel-of-oil-equivalent (BOE) basis. The following year, however, oil began to be favored over gas, a preference that grew more dramatic and by 2010 was more than $6 per BOE.

Today, that difference has shrunk to $3.80. Why? Barnes suggested one reason may be because the majors have few attractive alternatives globally for production growth and thus are being driven onshore North America, with four of the largest recent deals targeting gas.

"Petrohawk's reserves are 92% gas, although the headlines said, 'BHP buys oil company,'" Barnes said. Growth is the story, and there is no better place for that than North American gas. From February of this year to August, publicly traded oil companies that performed well across 2010 have traded down compared to gas-oriented companies.

Barnes said her firm has confidence there is room for growth-oriented gassy transactions. Pointing to the current forward curves, she asked, "How wrong will the strip be this time?"

Ramona Hovey, senior vice president of analysis and consulting with Drillinginfo Inc., discussed rig count, and the opportunities arising from lease expirations. Many leases from 2008 are starting to expire, including acreage from major rounds in the Bakken and Eagle Ford shales. Most activity has been focused on holding acreage in the major plays, she said.

Eagle Ford lease expirations appear to be distributed throughout the play, but the highest concentration is, in reality, in the oil and condensate windows. Expirations in the Haynesville are fairly scattered, but some acreage is expiring in core areas. Niobrara expires are mostly in the D-J Basin area, and Permian Basin Wolfcamp lease expirations are scattered. Barnett shale expiring acreage is in core areas, but there has not been a rush to pick up the slack, Hovey said.

"Can we drill the acreage set to expire with the rigs we have?" she asked. The answer depends on well spacing. More than a million acres will expire in the Bakken between now and 2012, but at 640-acre spacing, operators would need 89 weeks with the 70 rigs in the play (if averaging three weeks per well) to drill it up before leases expire.

"The reality is we are seeing a lot of 1,280-acre units there," said Hovey.

The Eagle Ford has more than a million acres expiring soon, with 200 rigs in the play. At 640-acre spacing—typical in the natural gas areas—it would be no problem to drill it in 32 weeks. At denser spacing like 160 acres, as is found in the condensate or oily areas, it would take 127 weeks. That is a lot less doable, and could imply an opportunity for companies controlling rigs to partner with those with acreage.

"The other component that always has to be addressed is who has the rigs," Hovey said. Big players have leases expiring and perhaps too few rigs available. EOG Resources Corp., for instance, has 145,000 acres set to expire between now and 2012, yet has only 20 rigs.

—Brian K. Tully

For more complete coverage of A&D deal-making, see A-Dcenter.com? .

Shale plays drive margins, demand higher for rigs, frac capacity

As the U.S. rig count continues to climb this fall, and operators focus on pad drilling and other efficiencies to make shale plays more economic, the demand for rigs, frac crews, pressure pumping and other services will continue to grow. Service margins are rising in tandem.

In late September, as Helmerich & Payne Inc. neared the end of its fiscal year, it reiterated that shale plays are driving the company's rig counts and dayrate margins higher. At the Barclays Capital CEO Energy-Power Conference in New York, the company said it has 221 land rigs working, and 148 of those are under term contracts as opposed to spot contracts.

It also has 38 FlexRigs under construction, with customer commitments, that are scheduled to be delivered in fiscal-year 2012, which begins October 1.

The company is increasing its rig count in the Eagle Ford, Woodford Cana and Fayetteville plays, as well as the Bakken and Permian Basin.

"The take-away: FQ4 appears to be tracking in line with our expectations (earnings per share of $1.04)," said analyst Brian Uhlmer in a recent report from Global Hunter Securities.

"What stands out is that it has 75 rigs contracted in the Eagle Ford…total domination," he added. For the drilling industry overall, he counts nearly 130 newbuild land rigs under construction backed by term contracts, "paired with at least another 30 known legacy rigs undergoing upgrades for second-half 2011 deployment. This implies the rig count should continue to trend higher, increasing demand for ancillary services."

Uhlmer forecasts the industry will require another 2,200 frac tanks (up 15%) over the final two quarters of 2011 and 1,300 more in 2012. He expects the average total capacity of pressure pumping for frac jobs will increase by 4.4 million horsepower through 2012 (up 41%), compared to the second quarter, "based on announced capacity additions and our forecasts. Assuming an average out-of-service time of about 10% for the industry's fleet, we expect total demand to continue to outpace capacity."

As of the week ending September 9, the Baker Hughes U.S. rig count tallied some 1,958 rigs at work, including 192 in the Eagle Ford shale, 186 in the Bakken and 128 in the Marcellus.

—Leslie Haines

Oil and gas jobs are on a record-setting incline

Texas: It's A Whole Other Country, a slogan the state uses to promote its travel industry, carries a much different meaning for oil and gas veterans in the Lone Star State. Visits to the Alamo and Padre Island aside, what's unique about Texas these days are the jobs created by the oil and gas industry. An Internet search for "Texas oil and gas employment" reveals an impressive volume of job listings, and in some cases, companies are scrambling to find workers. And energy jobs are growing in other states as well.

At NAPE's 2011 summer conference in Houston, John Christmann, Apache's vice president for the Permian region, said, "If anyone's looking for work, we need people in Midland, Texas. It may be tricky finding a house, but we definitely need people. If I could get more folks in Midland it would help us take our rig count up."

The current oil and gas employment statistics are record-setting, and that means job prospects have turned into paychecks.

According to the Texas Petro Index (TPI), 224,200 people held exploration and production jobs in the state in June. The employment count eclipsed the October 2008 mark, which was the peak of Texas' last major oil and gas boom. And in July the news was even better, as 6,200 Texans joined oil and gas payrolls, according to the TPI. The number of Texans working in upstream businesses now totals 230,400.

"Clearly, the crude-driven expansion of the Texas petroleum economy continues, with the TPI for July improving a stout 17% over the July 2010 index," said petroleum economist Karr Ingham, who created the TPI and writes monthly reports. "But the industry already has eclipsed the employment record, and other activity indicators are nearing peak levels.

"As long as prices hold above $80 per barrel, it is unlikely that activity will slow appreciably. It's possible the industry's growth rate could slow down if wellsite capabilities begin to reach their limits. Of course, all bets are off if crude oil prices begin to decline further," he added.

The favorable news about oil and gas employment is not limited to Texas. According to data published earlier this year by Economic Modeling Specialists Inc. (EMSI), an organization tracking labor market trends, regional economics and workforce development, the oil and gas industry dominated job growth in the U.S. from 2009 to 2011. The industry accounted for five of the nation's top 10 job categories, according to EMSI.

Service unit operator was the No. 1 high-growth job, followed by derrick operator, No. 2. Rotary drill operator came in at No. 4, followed by roustabout at No. 5. Petroleum engineer was No. 7. Together, the five oil and gas categories created about 20,900 new jobs during the two-year period.

Meanwhile, an early September report from Raymond James & Associates observes that the rig count is expected to grow faster than market expectations as long as oil prices remain greater than $70 per barrel. That is potentially uplifting news for job-seekers.

Raymond James revised its 2011 U.S. rig forecast upward by 4% to 1,881 rigs. For 2012, the domestic rig count is now expected to increase 10%, to 2,172. Beyond 2012, Raymond James expects U.S. drilling activity to continue increasing at a 10% annual growth rate.

Oil and gas employment prospects could become even brighter if the U.S. adopts policy changes that favor more production, according to a study released by the American Petroleum Institute (API) in early September. If such changes are adopted, the study suggests that more than 1.4 million new jobs, $800 billion in additional government revenue, and 10 million barrels of added daily production by 2030 could be generated. The study was conducted by Wood Mackenzie Research & Consulting.

"Our industry has kept more than 9 million Americans employed through some of the toughest economic times in America's history, and we created thousands of jobs just last month," API president and chief executive Jack Gerard said in a news release.

The suggested policy changes include opening non-park federal onshore and offshore areas to development where now prohibited; returning permitting in the Gulf of Mexico to historical levels; approving the Keystone XL and other pipelines; and establishing a regulatory environment that permits full development of the nation's oil and gas resources, including those locked in shale formations.

"The creation of these jobs is within the President's control," Gerard added. "The policy changes involve actions he can take unilaterally. They do not require a super committee of Congress and they do not require new legislation."

—Mike Madere

FBR Capital Markets: Expect slow recovery rate for Gulf drilling

Partisan rhetoric has been quick to blame political barriers for a drag in Gulf of Mexico (GOM) deepwater-drilling permits, but an early September analysis by FBR Capital Markets suggests those sentiments do not float.

Instead, the firm says the bottleneck stems from a more complicated permit-issuing process and a limited amount of bureaucratic resources to issue those permits. As a result, recovery of the deepwater permitting rate will continue to be slow going.

The Gulf drilling moratorium that went into effect after the Ma-condo blowout on April 20, 2010, had a major impact on the permitting cycle. Historically, the permitting backlog is three times the rig count, but the post-Macondo moratorium essentially wiped out that ratio. Thus, according to the FBR analysis, the permitting pace would need to increase significantly to rebuild a backlog to maintain the current count of 20 rigs.

The U.S. Department of the Interior in late February 2011 approved the first deepwater-drilling permit since the BP spill in the Gulf. The permit was granted to Noble Energy to resume drilling in 6,500 feet of water off the coast of Louisiana.

FBR's proprietary analysis of Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) deepwater-drilling permit approvals and other regulatory filings "leave us convinced that the current deepwater GOM active rig count of 20 is unsustainable at the current pace of permit approvals," says lead analyst Robert MacKenzie.

"Furthermore, unless the pace of permit approvals increases, we would expect between eight and 20 additional rigs to depart the deepwater GOM, in addition to the 12 that have already left or are committed to leave. Eight assumes that the pace of permitting picks up to support the current rig count, while 20 assumes today's pace of permit approval persists."

To support the current count of 20 active rigs, the backlog of permits approved but not yet completed needed to be roughly 60 at the end of August; however, the number was only 30.

Since the moratorium, a large number of deepwater rigs have remained active in the GOM doing completions, workovers or drilling the few wells that have been permitted, according to FBR.

"While we have no data on exactly how much non-drilling backlog remains, it's clearly being worked through rapidly with an active rig count that's roughly double what the backlog of drilling permits would seem to support," MacKenzie says.

"Another 10 rigs departing the U.S. GOM would represent 4% of the global marketed deepwater rig fleet of 253, and should be enough to limit potential day-rate increases. Between now and mid-2012, another seven deepwater rigs in the GOM are scheduled to finish their contracts, and there is always the potential for sublets under existing contracts or one or more of the three cold-stacked rigs to leave," he says.

This could be a headwind for deepwater drillers like Diamond Offshore while increasing the investment appeal of jackup-heavy drillers such as Rowan, Noble and Ensco.

FBR expects to see a step-up in the permitting pace from an average of three unique applications for permits to drill, including one new well from March through May, to an average of eight unique wells, including four new wells, from June through August 2011.

While BOEMRE has taken steps to smooth the permitting process, including a recent symposium for operators and the provision of new tools to help companies submit applications, the FBR analysis indicates there is no quick fix for restoring the pace of GOM drilling. "Even a 20% monthly improvement in the permitting pace at a 2:1 backlog still implies only a rig count of 22 by year-end. Also, we still see structural headwinds—hiring and funding constraints, potential safety and permitting legislation, pending drilling safety regulation revisions and ongoing environmental litigation," adds MacKenzie.

—Mike Madere

For more on the Gulf of Mexico post-Macondo, see OilandGasInvestor.com? .

Low gas prices are also a buying opportunity for end-users

Extraordinarily low natural gas prices are an opportunity not only for E&P buyers betting on higher forward prices, but also for other entities to capture returns from the high-Btu hydrocarbon's low price versus oil. This according to Ken Dewey, co-founder of oil and gas asset-transaction advisory firm Randall & Dewey, now part of investment-banking firm Jefferies & Co. Inc.

"From where I sit, the depressed natural gas price is an opportunity for, perhaps, different kinds of entities to become involved," Dewey said at Oil and Gas Investor and A&D Watch's recent 10th Annual A&D Strategies & Opportunities conference. Dewey and fellow co-founder Jack Randall were recognized at the conference with an A&D lifetime achievement award.

"There is potential for reindustrialization of our country with cheap and abundant natural gas."

Potential buyers are end-users, for example. "You have the chance now to have aluminum smelters, steel plants and chemical plants all to run on cheap and abundant gas. It's happening very slowly, but we have an industrial base now that could rely on cheap and abundant gas…with a good, creative approach to it."

Randall says, "On natural gas, it's this disconnect between what oil is worth and what gas is worth."

Currently, the oil:gas price ratio is 1:22. There are plenty of natural gas uses—gas to liquids, gas as a transportation fuel. "Despite all the good help we get out of Washington, maybe the (gas-production) industry is going to develop the nation's energy policy just by the market forces pushing people into gas."

What would Randall buy right now? History has shown that a buyer can't go wrong if the reservoir is long-life and complicated, he says. "Any reservoir that is a long-life reservoir…that's such a tremendous thing to have in an acquisition. Even if you guess wrong or the market has guessed wrong on prices, you are eventually going to get bailed out."

He also recommends that buyers admit to unknowns. "For an engineer, it is tough to recognize what we don't know. You do the best engineering in the world, we draw a 'p over Z' (decline) curve and we decide the pressure…." But the field may prove larger in time.

More complex reservoirs are usually under-valued in bids, he says. "The history of our business shows that these old fields get redeveloped and redeveloped."

Randall and Dewey were previously responsible for asset buying and selling at Amoco Corp., and have some 30 years of experience, each, in the oil and gas A&D business.

The toughest buyers and sellers can be private-company owners, Dewey says, "because every penny in negotiation is their own. They act like it's their money—because it is."

And, besides being based on all the science of reserves and production, buying and selling properties is emotional and unique to each party. Dewey says, "It's a people business. A lot of emotion is tied up in the whole horse race. People like to win; they don't like to lose."

—Nissa Darbonne

E&P redux: New oppportunities in plays of the past

A review of the current "state of the E&P business" may inspire an interesting sense of déjà vu, according to Michael Bodino, managing director and director of energy research, Global Hunter Securities. The number of land deals in play, majors' interest in U.S. onshore positions and the kinds of plays commanding attention are just a few of today's dominant E&P trends—and opportunities—that were also around during the 1980s, he says.

"We were definitely surprised to see that movies like 'The Karate Kid' and 'The Smurfs' were popular again, but, more importantly, we took note of what the 'hot areas' currently are, including the Permian Basin, Appalachia, and Cretaceous plays such as the D-J Basin and Austin Chalk," he told an audience at Oil and Gas Investor and A&D Watch's 10th Annual A&D Strategies & Opportunities conference.

Referring to a presentation slide that illustrated the early deposition pattern of the Lower Woodbine oil play in southeast Texas, he said that he's seen this kind of environment in several different basins.

"It's a very old concept, so today the industry is actually looking back at geological models it was reviewing decades ago. As we move forward in time to the newer Woodbine and the Eagle Ford, the Sabine Uplift becomes a dominant feature and we start seeing more sands and deposits from the northwest."

When GHS looked closer at the area within Madison, Walker and Grimes counties, it found that it wasn't just a Woodbine play; nor was it just an Eagle Ford play. Sequence stratigraphy showed the potential for up to nine producing horizons from the Glenn Rose formation all the way up to the Austin Chalk. There are also three unconventional shale plays above the Glen Rose that will likely be tested, he said.

Thirty years ago, the E&P industry was very focused on Permian, Jurassic and Cretaceous rocks.

Lower returns thwarted development activity for a period, but in the 1990s 3-D seismic became more accessible and higher returns and probabilities shifted to Tertiary-age rocks in the Gulf Coast and in the Gulf of Mexico.

Unconventional reservoirs stepped into the limelight in the late 1990s and early 2000s, and the pace of asset development accelerated thanks to horizontal drilling and improved completion technologies.

In 2008 events came full circle when the industry again began looking at younger rocks—Permian, Jurassic and Cretaceous—Bodino said.

"When you look at the resources that are being produced in the world now, the vast majority of production and reserves are coming from Jurassic and Cretaceous, with Cretaceous being the most prolific of all the rocks out there."

Why is there so much buzz behind a play like the Woodbine today? "The wells do come on at high rates, but there are also a lot of pay zones here that are prospective. We're looking at horizontal wells with 5,000-foot laterals and 20-plus frac stages and depths between 8,000 and 12,000 feet. There has already been significant production from multiple zones and additional upside exists with improvements in completions.

"The Upper Cretaceous section is approximately 40% silica and clastics that have natural fractures; the area is also a prime target for West Texas vertical commingling techniques.

"What is changing rapidly now is the application of modern drilling techniques. There are definitely opportunities in this area, much like what we are seeing in the Permian Basin."

—Bertie Taylor

Mexico aims to tap world's fourth-largest shale-gas reserves

With estimates of shale-gas reserves ranging from 150- to 680 trillion cubic feet (Tcf) and rapidly increasing domestic gas demand, Mexico is turning its attention to evaluating the massive shale-gas formations in the eastern half of the country.

Pemex Exploration & Production estimates shale-gas reserves of between 150- and 460 Tcf, while the U.S. Energy Information Administration puts the potential at 680 Tcf. A Pemex official declared earlier this year that the company would invest $8 billion to drill 4,000 wells and produce 1.0 billion cubic feet (Bcf) of shale gas per day.

Details of Mexico's shale-gas reserves and coalbed methane were discussed at a meeting, "New Opportunities for Unconventional Resources in Mexico: The Extension of the Eagle Ford Shale Play and Coalbed Methane Gas," hosted by the Institute for Energy Law's Oil and Gas Practice and International committees in Houston.

Luis Ramos, planning manager for Pemex E&P; Javier Estrada, commissioner of the National Commission for Hydrocarbons; Nicolas Borda, partner with Borda y Quintana; and Stan Harbison, vice president, research and analysis, Energy Policy Research Foundation, made presentations.

"Mexico has huge shale-gas reserves," Borda emphasized. "The reserves are fourth behind China, the U.S. and Argentina."

Pemex recently completed its first shale-gas well—the Emergente 1—that confirmed the Eagle Ford shale extends into Mexico in Coahuila state. The well cost an estimated $20 million to drill, and its initial production was nearly 3 million cubic feet per day (MMcf/d). The well was completed with 17 frac stages in a 4,500-foot lateral at a depth of 2,500 meters (8,250 feet). Production began from the well in May.

"The continuity of the Eagle Ford was proved by Emergente 1. We are now optimizing drilling and completion costs," Borda said.

"We have to accelerate the learning curve for the production of these resources. We have to generate predictive models of brittleness and ductility to define areas that are susceptible for hydraulic fracturing. We will evalu- ate the regional potential of shale gas and provide the best estimate of resources in place."

Pemex is focusing on five areas: Sabinas-Burro Picachos, Chihuahua, Burgos, Tampico-Misantla and Veracruz. Between 2011 and 2014, the company will drill at least 20 wells to evaluate these areas, depending on capex and what funds the government allocates to Pemex.

Mexico's current gas resources are around 61 Tcf. Even at the lower end of the Pemex reserve estimate, the shale-gas potential would more than double the current reserve estimates in the country, Borda said.

In the Burgos area, Pemex estimates there are 43,000 square kilometers of shale formations at depths from 2,500 to 4,000 meters (8,250 to 13,200 feet). The Eagle Ford and Agua Nueva shales are estimated to contain 27- to 87 Tcf.

"We have a program to drill six wells in the next two years to reduce the uncertainty," he said.

The Sabinas-Burro Picachos area covers 43,500 square kilometers with shale formations at depths of 1,000 to 5,000 meters (3,300 to 16,500 feet). Resources are estimated at 55- to 162 Tcf by Pemex. "We plan to drill six wells to evaluate the potential in the next year," he said.

The Tampico-Misantla region includes 37,000 square kilometers with shale at depths ranging from 1,000 to 5,000 meters (3,300 to 16,500 feet). The shale contains dry gas and light oil with reserves likely to be between 20- and 60 Tcf.

In Chihuahua, there are 33,000 square kilometers of shale formations at depths from 3,000 to 5,000 meters (9,900 to 16,500 feet). The shale gas is dry.

"We want to identify exploration locations in the plays. The La Casita, Eagle Ford, Pimlenta, Agua Nueva and Maltrata plays are where shale gas has been identified," Ramos said.

Estrada pointed out that gas demand is expected to grow by 2.4% per year from 2010 to 2025, according to the Mexican Department of Energy. By 2025, demand will be 5 billion cubic feet per day higher that it is today.

"Mexico has not promoted gas development," he said. "New infrastructure in transportation, storage and distribution is needed. We have limited transportation capacity in the country, and much of that is at full capacity."

The government is putting more pressure on Pemex to focus on gas. Estrada noted there is more emphasis on exploration in the deepwater Gulf of Mexico (water depths greater than 500 meters, or 1,650 feet). Sixteen wells have been drilled so far. Mostly gas has been discovered.

One field, Lakach, is being developed. The unit cost for developing this field is around $3.20 per thousand cubic feet (Mcf). The Piklis-1, with recoverable reserves of around 600 Bcf, will also likely be developed.

"If natural gas prices remain below $5 per Mcf, it will be very challenging to make deepwater developments economically viable," Estrada said.

Shale-gas estimates in U.S. fields range from $2 to $6 per Mcf for development, he added. "We have to study more gas markets before we can say what gas prices should be. Many gas projects have marginal economics and that's a reality. A tax regime for low prices will be needed."

There are risks to shale-gas projects, he noted. Groundwater will be a problem, since it takes 7- to 15 million liters of water to drill and frac each well. Other risks include noise, damage to roads, and traffic congestion and flow.

Regarding regulatory issues, "all regulations that apply to oil and gas production will apply to shale gas. Additional regulations are needed for administration, design, location, spacing, operations and abandonment," he said.

—Scott Weeden

Report: U.S. shale-gas development to hit $50 billion by 2015

The cost for products and services used in U.S. shale-gas development will grow to nearly $50 billion in 2015 as activity continues to escalate in the emerging Marcellus, Haynesville and Fayetteville shale plays, according to a recent report by MarketResearch. While shale gas drilling will slow from the rapid build-up of the 2005 to 2010 period, the industry will still bring more than 8,000 new producing wells online through 2015.

Increasing demand for drilling and completion products and services for new shale-gas wells will be accompanied by growing markets for workover, restimulation, and well-site reclamation services in areas where production is maturing.

Low natural gas prices since 2008 have narrowed the profit margin of shale-gas investment. Shale-gas producers are responding to this trend by seeking improvements in well economics, in many cases through the use of higher-value products and services. Through the forecast period, shale-gas producers will continue to embrace innovations such as multiple-well drilling pad systems and advanced hydraulic-fracturing materials to improve drilling efficiencies and increase per-well gas output, thus bolstering profitability as gas prices remain below 2008 highs.

Demand for drilling equipment and consumables in the shale-gas plays will grow to more than $6.8 billion in 2015, led by nearly double-digit growth in tubular goods, the largest equipment category. Shale operators will continue to consume more tubular goods overall and on a per-well basis.

Growth in demand for chemicals and materials will slightly outpace that seen for drilling equipment and consumables, reflecting the intensive material demands of the wells that will be drilled in the newer shale plays. Stimulation products, especially proppants, used in hydraulic fracturing,will be the dominant source of chemicals and materials demand.

The market for services used by shale-gas producers will reach more than $38 billion in 2015. Demand for services will continue to be dominated by contract drilling and pressure pumping, which together account for more than 60% of the total market. Service providers will continue to benefit from high levels of shale-gas drilling activity as well as the increased scale and sophistication of wells in the emerging plays, despite these trends slowing from the 2005 to 2010 period.

Other segments such as completion and production services and waste management and remediation services will be promoted by a range of factors. This will include increased workover and restimulation activity as well as new state and federal laws requiring additional environmental services at well sites.

Regional variations in the shale-gas market are strong due to geographical differences in recoverable reserves and the different stages of industry development in the major plays. The Southern region dominated products and services demand in 2010 and will retain half of the total market through the forecast period, even as the Midwestern region registers faster annual gains based on activity in the Marcellus, Woodford and a number of other emerging shale plays.

Through 2020, the Marcellus shale will be the fastest-growing market for products and services of the major plays.

—OilandGasInvestor.com ?

Permian Basin rules in first-half 2011 completions

A review of well completions in U.S. unconventional plays shows that 3,402 wells were reported in the first quarter of 2011, and another 2,885 were added in the second quarter. That brings first-half 2011 totals to 6,287 completed wells, according to Ann Priest-man, editor of Hart Energy's UG-? center.com ? website. Priestman compiled the statistics as of August 29, 2011, from IHS Inc. data.

Well completions were sorted by play, by operator and by county for UGCenter's quarterly update. In total, first-half 2011 wells were counted in 14 major unconventional plays, drilled by 298 operators.

Not surprisingly, the Permian Basin of West Texas and southeastern New Mexico led all unconventional areas with 1,258 completions. The large number of completions attests to the multiple pays in the prolific basin, including the Abo, Bone Spring, Leonard, Spraberry and Wolf-camp.

"The Permian is a new addition to our completions summary," says Priestman. "To date, the first-quarter Permian completions in our selected plays stand at 633, and second-quarter completions are at 625." Spraberry drilling dominated the mix, accounting for 906 of the first-half Permian reports.

Second overall rank for first-half completions by play was held by the Niobrara. As in the Permian, Niobrara drilling is mixed across established vertical production areas and newer horizontal sweet spots. Weld County, Colorado, accounted for 756 of the total 863 Niobrara completions. Top Niobrara operators, both with large legacy positions in the vertical drilling areas, were Anadarko Petroleum's Kerr McGee unit with 371 completions, and Noble Energy, with 213.

North Texas' Barnett play was a close third, based on number of completions. Chesapeake Energy, Devon Energy and EOG Resources each reported completions on more than 150 Barnett wells in the first half of the year. Other active operators included XTO (ExxonMobil) and Quicksilver Resources. Total Barnett completions stood at 831 at the time of Priestman's report. Tarrant County, in the heart of the play, was the most active county across the entire nation for first-half 2011 completions, posting 245.

The Piceance/Uinta area scored 781 first-half completions, but unlike other newer unconventional areas, work was confined to a select group. Anadarko Petroleum's Kerr-McGee unit, Newfield Exploration, Williams, and Bill Barrett Corp. each put up large totals, at 161, 144, 113 and 94 completions, respectively. The basin has been generating increasing interest, with Mancos and Uteland Butte shales joining the traditional objectives.

The Bakken/Three Forks, Eagle Ford, Fayetteville and Haynesville fell in a broad range, between 440 and 364 completions. North Dakota's Williams, McKenzie and Mountrail counties each boasted more than 80 completions, leading the Bakken/ Three Forks action. Dimmit County was tops for the Eagle Ford, while White and Van Buren counties in Arkansas were busiest for the Fayetteville. Those latter two counties each recorded just over 100 completions.

DeSoto was far and away the most active county in the Haynesville play, with 196 completions. The next most-active county was Caddo, with just 40.

Priestman noted that completions information tends to lag, so the counts from the plays covered in UGcenter's first-quarter completions summary have grown. As of April 30, 2011, 1,755 wells in 13 plays were reported by more than 130 operators. The jump to 3,402 completions is accounted for by the addition of the Permian plays, and by increases in individual plays as reporting continues over time. For instance, Bakken and Three Forks wells completed during the first quarter stood at 183 on April 30, and that total has now grown to 260.

From the operator perspective, Anadarko Petroleum and its Kerr McGee subsidiary led the list, reporting 628 first-half completions. The majority of these were in the Niobrara, in the traditional producing area of Wattenberg Field in Weld County, Colorado. Operators following Anadarko were Chesapeake Energy and Exxon-Mobil, with 425 and 378 completions, respectively. Chesapeake's wells were concentrated in the Barnett and Haynesville plays, while ExxonMobil's were spread among numerous plays, with the Barnett, Cotton Valley and Fayetteville each above 80 completions.

Rounding out the Top 5 were EOG Resources, with 303 completions, and Devon Energy, with 290 completions. The Barnett was the most active play for each.

—Peggy Williams

The completions report can be viewed and downloaded on UGcenter.com? .

Can U.S. independents apply leverage to China's shale gas?

In the past year, Chinese companies have been targeting the shale-gas operations of U.S. independents to get access to technology for developing resources in China. That points to the leverage that independent and mid-size oil and gas companies could have in the Chinese shale gas industry, according to Toshi Yoshida, corporate and energy partner at the law firm, Mayer Brown LLP.

"Within the next six to 12 months, there will be a lot of progress in shale gas in China," he told E&P On-Line. "What I sense from the Chinese government and companies is that they need to learn the technology of fracturing shale formations. It's a good chance for U.S. independents to form joint ventures with companies in China.

"U.S. independents, if they are serious about expanding globally, have very good leverage in negotiating with Chinese companies developing shale gas," he said.

Yoshida recently attended a shale-gas conference in China, where most of the attendees were Chinese. However, the interest in U.S. fracturing technology was intense.

"The key words at the conference were, 'We want to learn from the U.S.,'" he noted. "The Chinese are really serious. They are not confident about fracturing. They are sure they can drill horizontal wells since they have been doing that for coal-bed methane for several years. They need to learn from U.S. companies about shale-fracturing operations."

There is no official total for shale-gas reserves in China, although the U.S. Energy Information Administration has estimated China's shale-gas resource at 1,274 trillion cubic feet.

"The shale-gas industry is in a very early stage," Yoshida said.

"The first horizontal shale-gas well was drilled and completed by PetroChina in March in Sichuan Province. There has been no subsequent report on production. That indicates they are still evaluating the results of production from that well," Yoshida said. "They still need to learn about production from the well. And, they need to drill more wells."

Currently, there are only four Chinese companies that are allowed to develop shale-gas resources in China. Foreign companies can negotiate for joint ventures with the designated shale-gas companies.

U.S. companies, especially those with experience developing shale gas, will have an advantage. Most of the expertise in drilling and fracturing shale formations was developed by the independent, mid-sized companies. That's why Chinese companies like CNOOC have been investing in shale-gas plays in the U.S. with Chesapeake, for example.

"CNPC's joint venture with Encana, which fell through unfortunately, was a good attempt. It was not a joint partnership but a joint venture. The Chinese company would have had more direct access to the technology through the joint venture. If a company takes up a partnership as a non-operator, the operator doesn't have the requirement to share the technology," Yoshida said. "There is still a question of how they can transfer the technology."

Forming a joint partnership in China is pretty straightforward, he noted. "I don't see any problems for foreign companies. There is a lot of conventional drilling in China and there is no particular difference between conventional oil and gas or shale gas in forming a joint partnership.

—Scott Weeden

IHS: Greenhouse-gas emissions from shales overstated by EPA

Estimates used by the U.S. Environmental Protection Agency (EPA) and others for greenhouse-gas emissions from upstream shale-gas production are likely significantly overstated, according to a new report by IHS Cambridge Energy Research Associates (IHS CERA). The estimates are based on assumptions that do not reflect current industry practice and should be reevaluated, it says.

"Methane emissions have become a very important and controversial issue given their potency as a greenhouse gas," says Mary Barcella, IHS CERA director of North American natural gas.

"Unfortunately, such emissions are not being measured. Estimates are being used that are not supported by data, do not reflect current industry practice and would be unreliable to use as a base for decision-making."

The report cites as one example the EPA's 2010 revised estimates of methane emissions during well completion—the period after the well has been drilled but before it is placed into production. The current EPA methodology for estimating methane emitted during this phase was based on a small sample of wells and primarily measured methane that was captured rather than released into the atmosphere, the report says.

The EPA estimates were based on two workshop presentations describing methane captured during "green completions"—operations designed to capture as much methane as possible. The EPA assumed that similar levels of methane were produced at every other well in the U.S., and that those emissions went completely uncaptured. Such assumptions do not conform to current industry practices, the report says.

"The assumption that all methane recovered from these sample wells would otherwise have been flared or vented is questionable at best, given that common industry practice is to capture gas for sale as soon as it is technically feasible," says Surya Rajan, IHS CERA director.

"Gas that cannot be sold is generally flared rather than vented for safety reasons. If the methane emissions at wells were as high as some methodologies assume, you would have extremely hazardous conditions at the well site that neither regulators nor industry would permit."

Another key mischaracterization found in the EPA estimates and other recent reports, such as a study led by Cornell University professor Robert W. Howarth, is the assumption that wells in flow-back contain methane in quantities equal to their post-completion daily production, the report says. This assumption results in a significant overestimation of methane emissions. (The flow-back phase is the phase of production when fluids injected into the well flow back out ahead of the tapped gas.)

The IHS CERA report notes that data on unconventional gas well GHG emissions is currently lacking, due to the fact that they are not adequately measured. More reliable data is needed in order to produce estimates with any degree of certainty.

The report says that the most productive result of additional regulations proposed by the EPA in July could be better documentation of actual greenhouse-gas emissions, which would provide the accurate measurement that is needed. Some of the other proposed regulations, such as requiring green completions and flaring of any produced gas that is not suitable for sale, are already common practice in the industry, it says.

—OilandGasInvestor.com ?

Middle East tiger: The impact of the Libya conflict on oil markets

Which companies are winners and which are potential losers in the aftermath of the Libyan military conflict? The African country was the ninth-ranked oil producer in the world, producing roughly 1.8 million barrels per day, and sending out 85% of those reserves to foreign markets. Oil analysts say that Libya has about 80 years worth of oil reserves.

Now that Libyan rebels have the Muammar Qaddafi regime on the run, oil and gas speculators are already wondering who will benefit from the imminent change—via the National Transitional Council—from a revolutionary force to a viable, stable government.

U.S. oil companies with deals in place in Libya. Companies like Marathon Oil have a huge leg up on the competition. Marathon gets about 12% of its oil from Libya, although that volume has slowed since the military conflict intensified in early 2011. But it has existing contracts in Libya and should be among the first in line to start drilling as the country stabilizes.

Other U.S. oil providers that should benefit from the end of the Libyan conflict include Hess Corp., which counted 5% of its total oil revenues from Libya back in 2010; Conoco Philips, which counted 3.3% of its total oil production coming out of Libya in 2010; and Occidental Petroleum, which reported 2% of its oil revenues from Libya in 2010.

While each of the above companies was forced to rush to the sidelines during the military skirmish, the NTC has made it known that oil production is a huge priority, and that companies already in Libya can start up operations as soon as possible.

BP gains the most? First among equals in Libya could well be U.K.-based British Petroleum. Six months ago, the thinking among oil industry observers was that BP's $900-million exploration deal with Libya might be in jeopardy. The deal was signed in 2007, and was negotiated between BP and Libya's National Oil Co. About 21,000 acres of prime, oil-rich Libyan real estate were on the line. But now all systems are go for BP in Libya.

Italian oil company Eni. Libya has historically had close oil trade ties to Italy, and especially to Eni, the largest oil company in Italy. Industry insiders say that Eni should be one of the first companies at the table when the NTC starts discussing oil production in the aftermath of the Qaddafi regime. But Eni actually has had boots on the ground in Libya all along, providing 50,000 barrels of oil per day to Libyan rebels through the spring of 2011.

Eni has already announced an agreement with Libya to make emergency oil and gas available to the country, and won't ask for payment until the government gets back on its feet. The Italian government is sweetening the pot by offering to unfreeze about €350 million ($504 million in U.S. dollars) to help get the Libyan oil industry out of stall mode and into first gear. It's a symbiotic, buddy-buddy relationship that should strongly benefit Eni in Libya.

China's oil market. Over the long haul, both Chinese consumers and oil companies should be big beneficiaries of a stable Libya, but they may pay a short-term price first. Before the military unrest started, China had about 36,000 citizens in Libya, working on various oil and gas exploration projects.

In recent weeks, China's government has been especially diplomatic—even friendly—toward a Libyan regime change. According to government data, China has 75 companies in the country pouring billions of dollars into oil, transportation and technology projects. China pulled out a large number of its nationals operating in the region, but now that the military fireworks have abated, expect China to have all hands on deck in Libya.

—Brian O'Connell

Deloitte: Energy deals, values decline vs. first-half 2010

The quantity of M&A deals during the first half of 2011 rose and subsided with the price of a barrel of oil. That's the conclusion of the Deloitte Center for Energy Solutions in compiling its "Oil & Gas Mergers and Acquisitions Report" for midyear 2011. With commodity prices falling, Deloitte & Touche LLP's M&A transaction services practice partner Jim Dillavou says the volatile economy also has tamped down the number of M&A deals and their values.

"We think most of the decline can be attributed to the up-and-down process of deal-making," says Dillavou. "It also probably reflects the movement of oil prices, which ran up to near record highs and have now receded. The high prices likely caused some people to pause and reassess transaction values, but now that prices have softened, deal activity may return to trendline levels."

The total upstream deal count for first-half 2011 was 149, down from 164 in the first six months of 2010. Upstream M&A deal values dropped from $80.5 billion during the first half of 2010 to $53.6 billion during the same period in 2011, a 33.4% drop. The fall-off in value was due to several large international assets and corporate deals that occurred in 2010, according to Deloitte.

Deal activity so far in 2011 has remained concentrated in North America. Deloitte Tax LLP partner Jason Spann says, "U.S. shale plays are still attracting lots of deal activity and interest."

Prolonged weakness in natural gas prices is a significant factor driving the domestic E&P transaction market. The depressed prices are causing difficulties for small and midsized producers, providing incentives to sell off their assets. This in turn creates opportunities for majors with deep pockets and long-term time horizons, reports Deloitte.

Spann says, "We continue to see lots of consolidation in the E&P segment, particularly in U.S. oil and gas. The major companies have been active buyers, making significant multi-billion-dollar investments in shale plays."

The Eagle Ford and Marcellus shale plays have been big drivers of M&A deals. Deloitte Consulting LLP principal Trevear Thomas says the majors are taking advantage of the lower gas prices to buy up sound properties now to develop them when prices reach a more sustainable level.

The real area to keep an eye on is offshore U.S. Thomas says the regulatory situation in the Gulf of Mexico has improved and permits are being issued again, bringing back an upward trend in drilling.

"Deepwater is the next E&P frontier," says Thomas.

—Stephen Payne