In the borough of Indiana in southwestern Pennsylvania, the calming voice of hometown legend Jimmy Stewart coaches you through street crossings and Nap’s Cucina Mia serves the best Italian almost anywhere, according to the Sicilian along on the tour. Indiana is also the new hub for a Consol Energy Inc. field office, as the Pittsburgh-headquartered coal producer and natural gas explorer pushes the boundaries of the Marcellus shale’s southwestern sweet spot into neighboring Westmoreland County. Good news from the front: results look strong.

As rigs flee the gas-oriented and prolific Bar-nett and Haynesville shale-gas fields for more economic, liquids-producing plays, the vast Marcellus stands to overtake all other domestic gas plays as the top producer by the end of the decade, according to a recent study commissioned by the Marcellus Shale Coalition. Even though it is predominantly natural gas in a $4 gas-price market, the play remains resiliently economic to drill, bolstered by low finding and development costs and a positive price differential due to proximity to the bulk of American markets.

The Marcellus shale is “amazing,” says Range Resources Corp. chairman and chief executive John Pinkerton. “Nobody in their wildest dreams thought it was going to be this good.”

And it’s just big. Covering an estimated 50 million acres across West Virginia, Pennsylvania and New York (although the latter has imposed a hydraulic fracturing moratorium), E&P operators are just beginning to step out beyond the two known sweet spots in northeastern and southwestern Pennsylvania and fill in the blanks.

In an era when public independent operators are beating the drum of liquids-rich opportunities, the Marcellus stands as king of the gas-shale hill, with economics competitive with any North American play today. How good is it? The U.S. Department of Energy projects that the Marcellus has the potential to produce 17.5 billion cubic feet (Bcf) of gas per day—6.4 trillion annually—which would represent one-fourth of total U.S. gas production by 2020.

Taking a more conservative view, Hart Energy and Rystad Energy, in their North American Shale Quarterly service, estimate the Marcellus shale could produce 9.7 Bcfe per day by 2020, based on an exhaustive economic model that takes various constraints into consideration. These include, but are not limited to, rig activity, hydraulic fracturing capacity, infrastructure, and natural gas demand and price forecasts.

Based on findings in the Marcellus Shale Coalition study that focused on economic impacts of the shale in Pennsylvania, the state exited 2010 with 2 Bcf of daily production and is projected to hit 3.5 Bcf by year-end 2011. That number should top 12 Bcf in 2015, which would make Pennsylvania the No. 2 gas-producing state, behind only Texas.

“This dramatic increase in Marcellus drilling activity has occurred during a period of general economic recession and relatively low natural gas prices,” notes the study’s lead researcher, Dr. Timothy Considine. Considine, formerly with The Pennsylvania State University, which conducted the study, and now at the University of Wyoming, projects spending by producers in the play to continue increasing, from $11.5 billion in 2010 to $12.7- and $14.6 billion in 2011 and 2012, respectively. “The economic impacts of this level of production are significant.”

If the Barnett shale is the granddaddy of all shales, then the Marcellus is the mother, says Michael Bodino, senior analyst with Global Hunter Securities. “There is little question that Pennsylvania is poised to become the regional hub of North American natural gas production.” GHS’ model suggests it will take approximately 3,800 wells, or an additional 2,000, to reach 5.5 Bcfe per day and eclipse the Barnett and Haynesville shales as the biggest producing natural gas field in the U.S. “That could happen during second-half 2012,” he says.

“It’s amazing. Nobody in their wildest dreams ever thought it was going to be this good,” says John Pinkerton, chairman and chief executive of Range Resources Corp. “The Marcellus could have an impact on energy policy across the U.S. and potentially, the entire globe.”

And yet the play is beset with more than its share of surface challenges, as populations less familiar with oil and gas operations doubt industry best practices and production successes outpace infrastructure build-out. With so much potential lying in wait, the outcome lies largely in the collective response by the industry.

Projections put Marcellus daily production above 12 Bcfe per day by the end of 2015; year-to-date permits indicate rigs are not running away to wetter pastures.

Simplifying the process

If anyone knows the ins and outs of the Marcellus, it’s Range’s Pinkerton. Range, as everyone knows, is the little ol’ E&P headquartered in Fort Worth, Texas, that opened up the play, and the rest is history in the making.

“Back in October 2004, when we drilled the first well, we were just hoping we could make the play work and have it be special to us. We never thought it would be this big, and be so transformative,” he says.

Today, Range has 790,000 acres under lease in the Marcellus, with a solid 550,000 of those concentrated in the small but highly economic wet-gas spot in the southwestern corner of Pennsylvania. For a 5.7-Bcfe estimated ultimate recovery (EUR) well costing $4 million, the economics here are enviable: a 79% internal rate of return (IRR) based on just $4 gas.

While the published per-well EURs are in line with other operators, Range’s lateral lengths and number of stages in the completion process are notably shorter, at 2,800 feet, with nine stages. Why? Standardizing the completion minimizes the cost.

Pinkerton explains, “We were drilling such good wells and getting such good economics with 2,500- to 3,000-foot laterals that we decided, in this low-price environment, we needed to be very conscious of the capital. By simplifying the process, we could get much more bang for our buck. As shorter laterals mean we can drill more wells, we therefore are able to hold more acreage.”

With some 1,000 total industry wells in and around this position, Pinkerton considers this portion of the play derisked from an operational standpoint. “It’s just a matter of developing it out.” On 80-acre spacing risked 20%, that equals 5,000 possible locations in the wet. Eight rigs are presently focused on the task.

Further, Pinkerton believes the ethane potential from the company’s wet-gas production could top 500 million barrels. The company has now contracted with Nova Chemicals Corp. to begin transporting part of the ethane stream, and is looking to Dow Chemical Co. and others to absorb the rest as production increases. Export is an option he considers viable. The ethane is currently being sold for a modest up-sale in the gas stream.

In northeastern Pennsylvania, targeting decidedly leaner gas, Range holds 240,000 acres, primarily in Lycoming County. Here, reserves average 6 Bcf on a typical 2,500-foot lateral with nine frac stages. With an additional tap capacity of 350 million cubic feet (MMcf) per day being built, 27 additional wells will come online by the end of November.

“It’s not as economic as the wet gas, but it’s still economic at today’s price,” he says, although rates-of-return figures will have to wait until production comes online. He acknowledges the company would rather develop the acreage in a higher gas-price environment.

The need to hold acreage is driving the six rigs here, plus three nonoperated rigs. In total, Range would like to capture about 700,000 net acres of its whole, and expects to have half of its position locked up by year-end. The rest should be held in four to five years.

To execute the plan, Range raised $900 million earlier this year with the sale of its marquee Barnett shale holdings. After retiring all debt, $300 million remains on hand, combined with an undrawn $2-billion credit facility.

“We’re in terrific shape,” he says. Range’s Barnett team is now deployed to northeastern Pennsylvania, leaving the existing Marcellus team to concentrate on the wet-gas region. “Our view is to put your capital and your best people on your best project.”

That capital is riding on an estimated 22 to 32 Tcfe of net unproven resource potential in the Marcellus. Range expects to exit 2011 flowing 400 MMcf per day, double its previous year exit rate, and to achieve 600 MMcf flowing by the end of 2012.

“We think our mission has been laid out in front of us,” says Pinkerton. “When you find a giant gas field like we have, it’s pretty easy to figure out what we ought to be spending our time and effort on.”

Money and pipe are the two biggest challenges facing Marcellus operators, says EQT Corp.’s chairman, president and chief executive David Porges. The company is sitting on 20 Tcfe of resource potential.

Might the company be positioned for sale?

“We’re just in the infancy of the Marcellus, and the Upper Devonian and Utica, which covers a substantial amount of our acreage,” Pinkerton says. “We think we need to get these other formations drilled so we can get credit for them. Instead of letting somebody else’s shareholders get the benefit, our job is to develop this out to make sure Range’s shareholders get the benefit of those upsides.

“We haven’t even scratched the surface yet.”

Capital and capacity

Independent operators with swaths of resource potential in the Marcellus face two big challenges, says David Porges, chairman, president and chief executive of EQT Corp., a Pittsburgh, Pennsylvania-based company with both E&P and midstream business units.

The first challenge: money. How does a company amass the enormous amount of capital needed to develop the play?

“The opportunity set for companies like ours is far greater in magnitude than our ability to finance investments. We are looking for coins behind the sofa cushion to fund these remarkably attractive investments,” says Porges.

EQT’s position consists of 520,000 acres in three distinct regions—southwestern and central Pennsylvania in dry-gas zones, and in northwestern West Virginia with both dry- and wet-gas opportunities. The positions hold some 20 Tcfe of estimated total resource potential.

In 2011, EQT started with $413 million earmarked for Marcellus drilling. But already this year the $9-billion market-cap company has sold a Kentucky processing plant and its Big Sandy pipeline, banking $620 million toward Marcellus acceleration. EQT is evaluating other assets and opportunities to raise cash as well, including coalbed-methane holdings in Virginia, Huron shale assets in Kentucky, and its EQT Midstream business.

“We are underinvesting in those assets,” admits Porges. “We can’t warrant putting in the money that those assets deserve when competing against investments in the Marcellus.”

Options to monetization include straight asset sales or creating royalty trusts or joint ventures in any non-Marcellus asset. Porges is evaluating carving out the midstream business into an MLP for possible sale. He unequivocally rules out issuing equity, and considers a Marcellus joint venture an option of last resort, despite JVs’ popularity among his peer group.

“We believe we can generate more value on our own than through a joint venture.” With per-acre values ranging between $6,000 and $13,000, when adjusting for present value, “it’s easily double the high end,” he says. “Having half of that is not very attractive.”

The second big issue: Volumes are growing so rapidly that infrastructure cannot keep pace.

“Our volume growth rate the last two quarters vs. the same quarter last year is north of 40% total company, and just the Marcellus is way higher than that.” Gathering pipe, compressor stations and long-line pipes to get gas to market are in high demand for producers driving capital into the Marcellus. “We’re all putting a lot of iron in the ground, but these projects take time.”

Consol’s first three wells in Westmoreland County, Pennsylvania, DeArmitt 1A, 1B and 1C, were drilled in December 2010, but didn’t go online until the day before this photo was taken, in mid-September, due to a long pipeline permitting process. The wells are expected to flow a combined 40 MMcf per day by year-end.

Like others, EQT must measure its pace with the growth of available take-away capacity in its operating regions, but unlike others, the company better controls its flows and build-out strategy through its own midstream business, which owns the Equitrans pipeline.

“Our midstream projects support only EQT Production, and EQT Production accounts for most of the Equitrans volume on new investments that we are making. We are building like crazy, but it is still hard to keep up with volume growth.”

While Porges sees having influence over the midstream as a value creator, he also recognizes the conundrum of choosing where to place scarce capital. “It’s a tradeoff. That capital (to support the midstream) comes away from Marcellus drilling, but by the same token, investing capital in Marcellus wells when you can’t get the gas to market is no better.”

Even without additional capital infusion, the company models growing overall volumes 30% annually for five years using cash on hand, cash flow and debt capacity. “We’re in an enviable position of having an attractive plan even if we didn’t sell another asset,” he says, “but frankly, given the set of opportunities, optimal would be somewhat higher.”

Below surface, EQT is pushing out the boundaries of its hydraulic fracturing geometry. In contrast to its standard 300-foot stage with 60 feet between perforation clusters, the new completion jams clusters every 30 feet apart within a 150-foot stage. The same amount of water and sand per foot is pumped into the ground, achieving double the injection rate per foot.

The tests have resulted in 60% higher initial production (IP) rates over 13 wells, but the jury is still out on whether the tighter clusters will result in higher EURs, or merely accelerate volumes. And costing an additional $1.6 million per well with a 5,300-foot lateral, the economics must prove out: A minimum 10% bump in recovery is needed above the current 5.7 Bcfe per well.

“In the capital-constrained situation we’re in, increasing the early-year volumes is beneficial—you ramp up the cash flow earlier, but it does mean you have more decline later.”

The company is on track to exit the year with 100 wells drilled into the Marcellus, of which about 27 will sport the new frac design. Targeted production is 285 MMcf per day.

All in after taxes, including a presumed Pennsylvania severance tax, EQT is running economics at a 70% IRR on the strip price, and “well north of hurdle rates” at the current spot price. “The Marcellus is very economic for us,” he says. That translates to revenues and jobs for Pennsylvania and West Virginia. Those states “are going to look a lot more economically attractive in five years” due to Marcellus activity, Porges predicts.

Consol is expanding the DeArmitt pad to accommodate six additional wells.

Gas switching

A lingering fog laces the landscape around Consol’s DeArmitt pad on an early September morning in Westmoreland County, Pennsylvania. The three-well pad, Consol’s first horizontal Marcellus effort from its central Pennsylvania Indiana office, is a stepout from its core focus in Greene and Fayette counties further south.

The DeArmitt wells, drilled in December 2010, had just gone on production the day before, the beneficiary of a long-anticipated new compressor station and transmission line. Illustrating typical surface challenges of the day, this particular pipeline took 270 days to permit, held up by both the U.S. Army Corps of Engineers and the Environmental Protection Agency, due to being in an environmentally sensitive area. The wells are producing 8.7 MMcf of 1,000 Btu gas per day, combined, on a choke.

“When you delay bringing on several million cubic feet of gas a day for six months, that’s a pretty costly delay,” notes Consol chief operating officer Randy Albert.

Yet the pipe means Consol can now move forward in this region. “That transmission line gives us unlimited capacity for all our new wells,” says Joe Zoka, Consol general manager for central Pennsylvania. “When we came up here there was nothing. The magnitude of this year-long project is huge. Now, we can drill and connect all that we see fit to develop.”

The compressor station can handle 150 MMcf per day. DeArmitt alone will deliver 40 million-plus by year-end, Zoka says. Another 10-well pad, the Hutchinson, is being completed, the eight-well Aiken is drilling, and four more are being topholed at Gaut. The drill sites march in sequence around a reservoir where Consol sources its frac water.

Consol chief operating officer Randy Albert notes the early results from Westmoreland County look “very encouraging.”

Early results from Westmoreland County look “very encouraging,” says Albert. “They look to be Greene County-type numbers,” referring to the company’s core operation. “We’re very excited.”

Zoka says historical data is being built daily in this new region. “That’s how quickly this is coming along. I’m looking forward to downloading the data today.”

One vertical and one horizontal rig work out of this northern office; two more verticals were due in October to further step out into Jefferson County, with another horizontal flex rig scheduled at the first of the year. The company presently has a total of five horizontal rigs drilling Marcellus.

Most of Consol’s action and all of its prior Marcellus production is in the dry-gas zone of Greene County, where it has drilled 54 wells over the past three years producing 102 MMcf per day. Two horizontal rigs are dedicated here. Lateral lengths have grown from 1,500 feet in the early days to beyond 6,000 feet currently. Average EUR per well is 4.2 Bcfe with a maximum of approximately 9 Bcfe, but “the longer laterals beyond 6,000 feet have yet to be fracture stimulated, so we are anxiously awaiting the results of those wells later in 2011,” says Albert. “We’re firmly of the belief that the longer the lateral the better.”

In this region, typical IPs are up to 8.6 MMcf per day, with the highest single well currently producing 7 MMcf per day.

In Upshur County in northern West Virginia, the company is testing the southern fringes of what it believes to be the economic Marcellus shale. These wells initially produced 2 and 2.5 MMcf per day. Says Albert, “If that’s as bad as it gets, then we like our acreage between there and Greene County.” Since then, two more wells have come online in Barbour County, but results have not been released. “They’re very favorable,” Albert says. “We like what we saw in Barbour.”

In August, Consol partnered with Houston-based independent Noble Energy Inc., sharing 50% of its total Marcellus position for $1.1 billion plus $2.1 billion in the form of a drilling carry. Noble will operate in the wet-gas region of Greene County and in Marshall County, West Virginia. The first rig on the wet-gas acreage is now in place.

With 88% of its land held by production, why pursue a joint venture when not facing lease expirations? “It was simply a way to accelerate value,” Albert explains. “We have 750,000 acres to develop that we weren’t going to get to in the near future. A dollar 20 years from now doesn’t have a lot of present value today.”

The urgency to drill was also provoked by political winds blowing against coal, he says, which first motivated the acquisition of Dominion Resources Inc.’s gas assets last spring, quadrupling the company’s Marcellus holdings.

“When you look at the energy situation in this country, coal-fired power plants are going to be shut down and replaced by gas-fired plants. We can see the writing on the wall with coal. Our growth at Consol is going to come from the gas sector.”

If Consol’s coal customers decide to switch to gas in the future, he says, “We’ll be uniquely positioned to take advantage of that.”

The Hutchinson pad completions involve 2,500- to 5,000-foot laterals with 300-foot stages and eight to 18 stages per well. Consol is using 350,000 gallons of water and 350,000 pounds of sand per stage.

Consol has drilled 40 Marcellus wells year to date, with 85 planned. It expects to exit 2011 producing 150 MMcf per day. The company plans to ramp up to 16 rigs by 2014, adding one each quarter, with Noble operating six.

From Albert’s viewpoint, the Marcellus is still a baby in terms of operational maturity. “What we’ve learned in the past three months tells me it’s still very much an infant. Think about how large it is and how little we’ve drilled. We’re going to be another couple of years into it before we have the operational risks delineated.”

Where risk meets reward

With a market cap of about $246 million, Gastar Exploration Ltd. has the distinction of being the highest-leveraged public company to the Marcellus shale—by two times the exposure of the next company. And president and chief executive J. Russell Porter is enthused by the opportunity underlying that fact.

While it holds some 74,000 net acres across the play, Gastar is concentrating its efforts on 6,700 net acres in the high-Btu, liquids-rich area of Marshall and Wetzel counties in the thumb of West Virginia.

“We live in a world of finite capital, so we’re going to chase the best returns on a risk/reward basis,” says Porter. “Right now, this liquids-rich sweet spot has by far superior returns to anything else we’ve got in the company. It’s going to be our focus and create a lot of value for us.”

There, Gastar has drilled and completed its first two horizontal wells this year, which went online in August and tested at a peak initial combined rate of 11 MMcf and 410 barrels of condensate per day, followed by a 30-day rate of 7.1 MMcf and 176 barrels per day.

Gastar Exploration is concentrating all its efforts on its liquids-rich sweet spot with “far superior returns than anything else in the company,” says president and chief executive J. Russell Porter.

“We’re producing gas that’s a little less than 1,300 Btus, which means we’ll get about two and a half gallons of natural gas liquids (NGLs) per Mcf. In addition to that, we’re also producing about 30 to 40 barrels of condensate per Mcf of gas. It’s separate and apart from the NGL yield.”

With a total net realized gas price per Mcf equivalent of about $8.70 all in—with some $5 from the condensate and NGLs—he says, “This is more of an NGL and condensate play with gas than vice versa. Our economics on these wells are just fantastic when you factor in the fact that 75% of our costs this year are being carried by our JV partner.”

Make that an 80% to 130% internal rate of return, even before considering the 75% drill carry it is receiving from private-equity partner Atinum Partners Co. Ltd. At $7 million gross per well, South Korea-based Atinum is funding Gastar’s first $40 million of expenses before returning to a 50-50 heads-up partnership, which should occur in first-quarter 2012. The wells, which are about 35% liquids, show initial gross EURs of about 8.3 Bcf per well.

The company currently has an additional 12 wells drilling or waiting on completion. With three rigs plying the region—one topholer and two deep rigs—the company anticipates exiting the year with nine wells producing and another dozen in process.

Porter says the company was lucky in designing nearly optimal spacing between wells and frac stages early in its development program. Using microseismic analysis, the company found an advantage to having all the laterals within a unit of equal length due to the effects a fracture stimulation in one well has on the surrounding rock when adjacent wells are stimulated.

“We’re working everywhere we can to have these units set up so we can have at least 5,000-foot laterals that are close to equal lengths across the unit.”

In 2011, $48 million was dedicated to Marcellus drilling and land acquisitions for 37 gross wells (13.7 net); in 2012 that amount will ramp to about 80% of an estimated $100- to $120-million total capex.

Although Gastar holds positions in two other areas with dry Marcellus gas, Porter says the company will focus on the liquids-rich Marshall/Wetzel acreage until fully developed over the next two to three years. “We’ve got over 100 wells to drill and easily over three-quarters of a billion dollars in net present value to us there.”

Porter says Gastar has ample liquidity to carry out its development program in Marshall and Wetzel counties through proceeds from a preferred stock offering, internally generated cash flow or, if necessary, through proceeds from its unused borrowing capacity.

The company has to date raised $17 million through a preferred stock offering that is ongoing. “Our goal is to raise between $90- and $100 million. That would allow us to fully fund our programs through 2012 with nothing drawn on our credit facilities.”

If needed, the borrowing base is $50 million with $8 million drawn at the end of the second quarter, and that capacity does not include credit for the company’s Marcellus reserves. “That base is going to increase rapidly as we bring on these Marcellus wells.”

Gastar is targeting 28 to 36 wells next year. With no lease expiration issues in its Marshall/Wetzel counties region, all of Gastar’s Marcellus wells are being drilled on pads, with four to six wells per pad.

“The efficiencies and logistics make it a lot more economic once you get a rig on these pads to leave it there and drill out the whole pad, then complete all the wells back to back. That gives you a stair-stepped, lumpy production growth profile, but it gives you the best economics.”

And dry-gas leases don’t begin expiring until 2015. “We can take our time from a lease perspective,” he says, “but we’re very impatient from a returns perspective—we want to get this money in the ground and start generating returns as quickly as possible.”

The end of waiting

“We think the Marcellus is the most profitable gas play in the country, so we’re still focused there,” says S.P. (Chip) Johnson, president and chief executive of Carrizo Oil & Gas Inc.

The Houston-based company is on the front end of its program there, having dedicated $41 million to the play and drilled its first wells there this year. Carrizo controls some 118,000 net Marcellus acres in three operating regions: northeastern Pennsylvania, the “C” counties—Clearfield, Cambria and Centre—in central Pennsylvania, and in northern West Virginia. The Marcellus is by far the largest holding of any of its shale plays.

In Pennsylvania, Carrizo operates under a joint-venture arrangement with Reliance Industries Ltd., which holds a 60% nonoperated interest. “We get to invest somebody else’s capital while we’re waiting on production to come on,” he says.

Bottom, Carrizo Oil & Gas is enthused by its 116,000 Marcellus acres and lucrative drilling partnership, says president and chief executive Chip Johnson.

In the northeast, the company is using one vertical and two horizontal rigs, but has no production as yet. “We’ve been drilling and building a backlog of 16 wells,” says Johnson, “but we haven’t been fracing because the pipelines to us aren’t built yet.”

That issue was supposed to have been resolved by the end of September as the Laser pipeline was completed. “A lot of companies in Susquehanna have been waiting on that,” he says. Carrizo has 60 MMcf per day of firm capacity contracted for the pipe. It initiated its first two fracs in September.

Here, Johnson plans to focus one rig in Susquehanna County and another one in Wyoming County for two to three years, then add a rig in Sullivan County during 2012. “We should be in full-scale development by the end of 2012, as there is enough data to know it is going to work and work well.”

Central Pennsylvania is less certain, and the company plans one to two rigs drilling a test program, with first pilot holes drilled in November. Take-away remains unresolved: Carrizo is working with a private midstream company presently to build gathering lines to connect with the Columbia Gas pipeline running through the county.

In northern West Virginia, where the company is partnered 50-50 with Avista Capital Partners, it is building a pad and seeking a rig. Johnson plans to expand holdings there by some 10,000 acres.

Johnson anticipates at least eight wells will be connected to sales by year-end, with another 10 drilled or drilling.

Carrizo is ramping up the Marcellus program in 2012 to $104 million in capex and five gross rigs. With its partners, Johnson says the company has all the capital needed to meet the challenge using cash flow and its borrowing base.

“We have to pace development with cash flow,” he says. “It would be nice to run 12 rigs next year, but we don’t have the results yet, plus we don’t have the infrastructure.”

Chesapeake Energy likes its other liquids-oriented plays, but with 1.75 million acres and a 40% return, drilling in the Marcellus is “not like we’re throwing away dollars,” says executive vice president of operations Steve Dixon. “For gas, that’s as good as it gets.”

Gas vs. liquids plays

To hear Chesapeake today, the company is all about its liquids-rich plays in the Anadarko Basin and the Eagle Ford, Utica and Niobrara shales, among others. But as the company touts the economic returns of its new, wetter focal areas, its mighty Marcellus program marches along quietly in the background.

“It’s a pretty big chunk of our capital spend,” confirms Steve Dixon, Chesapeake’s executive vice president of operations and geosciences, “with about $800 million planned for 2012. The economics in the Marcellus are still good, and we’re getting higher-than-expected production in northern Pennsylvania.”

At a 40% rate of return, while not as high as the company’s liquids plays, “it’s not like we’re throwing away dollars. For gas, that’s as good as it gets.” The returns are even better considering the company’s costs are being carried 75% by Norway’s Statoil ASA, a partnership forged in late 2008.

Chesapeake is running 30 rigs in the Marcellus, a number that will “hold steady” into next year, says Dixon. “It’s a big area and we’ve got a lot of land to prove up. We’re having good results; we keep raising our expectations in the Marcellus.”

With about half of its 1.75 million acres held by production, Dixon figures another two years will hold the remainder. Twenty rigs are commissioned to northeastern Pennsylvania in Bradford, Susquehanna, Tioga and Sullivan counties. The rest are in the southern and wet portion of the play in Greene County, Pennsylvania, and in northern West Virginia in Wetzel, Marshall, Ohio and Brooke counties.

Total Marcellus production at press time was more than 750 MMcf per day, making Chesapeake the top producer and “growing rapidly,” he says, partly due to expanding take-away capacity. That could top 1 Bcf by year-end on the backs of 315 wells drilled in 2011. “We have the potential to double that again next year.”

An average Chesapeake lateral extends to between 5,200 and 5,500 feet. Dixon says the company spends a lot of effort geosteering wells for optimal placement in the formation. With more than 2.75 million acres of 3-D seismic and 8,000 feet of core from 125 pilot holes, “we’re still trying to understand where the Marcellus is the thickest and how to maximize production from what we’re contacting with our stimulations.”

A statue of Jimmy Stewart stands outside the courthouse in Indiana, Pennsylvania, where the iconic actor and WWII pilot was born. Facing page, one of four covered bridges in Indiana County, the 68-foot Kintersburg bridge spans Crooked Creek.

As a result of those efforts, IPs and EURs have trended up “quite significantly.” Where the company modeled 2 Bcf EUR three years ago, wells in the northern region average 6 Bcf now, with some topping 10 Bcf. Compare that with an average 3.3 Bcf EUR in the Barnett.

Surface issues have been a struggle, says Dixon, but the company has been proactive in meeting them. It recycles 97% of its water to address sourcing and disposal issues, and has built a series of water impoundments that can store up to six months of water needs, minimizing development delays when water sourcing is temporarily constrained.

The company also spends additional dollars on casing and cementing, perimeter berming, erosion controls and closed-loop systems. “Those things all cost extra—over a half a million dollars easy—but the play supports it.”

Chesapeake also holds acreage in the New York Marcellus, where Dixon is cautiously optimistic the moratorium on hydraulic fracturing will be lifted.

“As a practical matter, we can only focus on responsible development of the areas where we are permitted to operate, but we are confident our record of safety will win the day. The real risk to New York is not fracing, it’s the potential loss of its workforce to other states that encourage the very jobs New York has chosen to deny itself.”