The recent Marathon-Hilcorp deal for $3.5 billion illustrates the value proposition of the Eagle Ford shale: At a raw $25,000 an acre—undiscounted before production deductions—the acquisition set a new high-water mark for the play. But it was the proven liquids-prone production that set the metrics apart, highlighting why operators have a ravenous appetite to add Eagle Ford assets to portfolios.

Data research firm Evaluate Energy projects the Eagle Ford shale may soon become the biggest producing shale play in Texas, if not the entire U.S. With current production of 66,000 barrels of oil equivalent (BOE) per day, it remains overshadowed by its more mature neighbors, the Barnett shale (877,000 BOE per day) and the Haynesville shale (708,000 BOE per day). But a surge in new wells suggests that is about to change.

Magnum Hunter Resources Corp. has completed most of its Eagle Ford wells with 14 to 16 fracture stages. Here, a rig drills for the company in the South Texas shale play.

"Drilling activity in the counties that hold the Eagle Ford formation has been growing dramatically for the past year, and now, at the end of the first quarter, is the area with the most new wells being drilled in the state. Up until a year ago, drilling was negligible," according to the Evaluate Energy report. "The Eagle Ford play is looking like it will soon catch up with and overtake its neighbors."

Any way it's sliced, holding Eagle Ford assets represents great value. Here is a snapshot of several operators discussing recent data points and growing pains in the proliferating play.

Going longer, getting cheaper

Magnum Hunter Resources Corp. chief executive officer Gary Evans told investors at IPAA's OGIS New York recently, "One of the things we're striving to do in the Eagle Ford is to go out further."

With seven wells completed and producing in the play, the company has upsized from 4,000-foot laterals to its most recent of 6,000 feet, although 800 feet was lost at the toe due to mechanical problems. "We're fracing more stages, too," he said. "We're trying to get up to 20 stages per well." Most Magnum Hunter wells to date were completed with 14 to 16 fracture stages.

The company holds 25,000 net acres play-wide, most of those part of 50%-operated joint-venture partnerships with Hunt Oil Co., EOG Resources Inc. and GeoSouthern Energy Corp. Most of its acreage is concentrated in the oil window of Gonzalez County, with some in Fayette, Lee and Atascosa counties. Here, the average thickness of the Eagle Ford is 75 to 150 feet, with 8% to 10% porosity and 60% to 80% brittle rock.

Its latest wells drilled have averaged 1,200 to 1,300 BOE per day. "Our goal is to get to 2,000 BOE per day per well IP (initial production)," Evans said. Current wells are typically leveling out at 400 to 600 barrels per day. Production is 98% oil, "not condensate," he clarified.

Magnum Hunter is running one rig, and Hunt has another focused on JV acreage. Evans expects to have 15 wells on production by year-end 2011.

SunTrust Robinson Humphrey analyst Neal Dingmann says Magnum Hunter's Eagle Ford position has tremendous upside. "With recent well results in the area surpassing 1,000 BOE per day, we believe huge upcoming growth for Magnum should be expected in the play. Being largely in the oil window should help ensure that well economics remain high going forward."

Well costs are near $8.2 million at present, but Evans is determined to drive costs down. "The last well we drilled was $7.5 million; our goal is to get to $7.2 million," Evans said.

Monitoring service companies is crucial to keeping costs down, he told investors. "We hammer on these guys. If you've got 10 pump trucks and we only need eight, send the other two home. Don't charge us for that." Magnum Hunter also buys a lot of its own equipment, whether lighting, frac tanks or well agitators. "We've been able to drive costs down."

Data research firm Evaluate Energy projects the Eagle Ford shale may soon become the biggest producing shale play in Texas, if not the entire U.S.

Dealing quickly with mechanical issues is another focus of cost cutting.

"When something goes wrong—cut and run," he advised. "You stay there for three days fooling around trying to trip a hole, and that's when your costs go out the roof."

One big problem Eagle Ford operators encounter that affects the success of a well is staying in zone. "Steering is crucial for staying in zone. We're 100%. We don't get out of zone," he said.

Magnum Hunter runs high-case and low-case economics. Based on a 1,280-barrel-per-day model with a 500,000 barrels equivalent estimated ultimate recovery (EUR), the internal rate of return (IRR) is 36% at $80 oil, and 64% at $100. Modeling 613 barrels per day and a 362,000 barrels equivalent EUR, a low case, the IRR is 23% at $80 and 39% at $100.

Magnum Hunter has paid an average of $375 per acre for its position, he said, but today acreage is leasing for around $1,500 to $2,000. He will only pay that if it is "right in the fairway where we want to be."

The company is experimenting with new technology in Atascosa County, where it has 3,000 acres that are 100% operated, with two producing wells.

"We're willing to try new things; there are better ways to do this. A year or two from now we'll be doing things differently than we're doing them today. Look at all these resource plays; you're seeing better recoveries, better production, and better reserves… because we're learning."

Rosetta rising

"Our Eagle Ford assets continue to outperform our expectations." So says Rosetta Resources Inc. chief executive and president Randy Limbacher, summing up first-quarter 2011 during a conference call to investors.

Rosetta holds 65,000 total acres in the Eagle Ford play, but it has focused its attention heretofore on its 26,500-acre Gates Ranch prospect in northern Webb County. During the quarter, Rosetta drilled nine wells here, and has current production of 120 million cubic feet equivalent (MMcfe) per day, up from exactly zero 18 months prior. "Impressive," states Wunderlich Securities analyst Irene Haas.

In fact, the strong well performance makes the Houston-based company's published 7.2-billion-cubic-feet-equivalent (Bcfe) type curve obsolete. "The Eagle Ford wells are behaving nicely," Haas observes. "The data clearly shows that the newer wells are producing at higher rates than implied by the 7.2-Bcfe type curve."

And those newer wells are curtailed by some 15- to 20 MMcfe per day, due to short-term infrastructure constraints. Rosetta's senior vice president of asset development, John Clayton, quipped, "We'd like to see what these wells can do when they're not curtailed."

KeyBanc Capital Market's Jack Aydin is willing to take a guess: "We estimate EURs could be well north of 8.5 Bcfe per well on average in the Gates Ranch area."

The company has begun three-well pad development, resulting in a cost savings of $500,000 per well. Add to that an attractive lease operating expense of $0.15.

"Rosetta continues to optimize drilling and completion operations, which have offset service-cost inflation," says Michael Bodino, managing director and head of energy research for Global Hunter Securities. "Spud-to-release has decreased over the past 15 months from 27 days to 15, and pad development allows the rig to mobilize in hours rather than the previous five to seven days."

Downspacing remains imminent, as the company believes it is recovering just 20% of hydrocarbons in place. "The current well inventory of 236 wells is based on spacing of roughly 80 to 110 acres," notes Haas. "If downspacing is feasible, the Gates Ranch well count could double to 441. Using the current type curve of 7.2 Bcfe per well, this implies an incremental 1.5 trillion cubic feet equivalent (Tcfe) before royalty."

Wireline is run during frac operations in the busy Eagle Ford shale play.

Bolstered by recent asset sales and $385 million in liquidity, Rosetta has added a third rig to its program to test acreage beyond Gates Ranch, specifically 25,000 acres in the liquids windows in southern Gonzalez, central Dimmit, northern LaSalle and Encinal counties. It plans to have 58 horizontal wells drilled and completed by year-end.

But with the ramp up comes challenges. Even with firm take-away commitments in hand, Limbacher continues to closely watch the midstream infrastructure situation.

"Two potential pressure points are trucking capacity and the reliability of firm gas transportation," he says.

Oil hauling in South Texas is extremely tight and will continue to be for some time, he said. The company has sufficient trucking capacity now, but is moving toward other solutions such as rail, additional pipelines and barges.

Gas take-away is challenged as well, even with firm commitments for existing production. "We've seen our midstream partners struggling from time to time to provide firm capacity for which we've contracted," he says. Rosetta has moved gas to other carriers on a short-term basis. "Expect us to continue to develop additional take-away options to ensure plenty of gas pipeline capacity for our key projects."

Targeting take-away

Holding 250,000 net acres in the Eagle Ford shale, SM Energy president and chief executive Tony Best told investors at OGIS, "This is a company-maker for SM Energy. It's a great position."

SM holds 165,000 net 100%-operated acres, mostly in the rich-gas window in Webb and LaSalle counties. Here, the company is working three rigs at present, and plans to gear up to six by year-end. The company also holds a 25% nonoperated position of 85,000 net acres with Anadarko Petroleum Corp. in Maverick and Dimmit counties, with 10 rigs running.

Foremost on Best's mind was take-away capacity, and he wanted to assure that the company is in a good position to handle its increasing production.

"We've been able to secure significant take-away capacity, and we've contracted for the drilling and completion services that we're going to need for this year and next. That is going to be critical in our ability to ramp up in the program."

SM now has take-away commitments for 150 MMcf per day through midyear, going to 300 MMcf per day by the end of 2012. It has also secured a new take-away agreement for an additional 190 MMcf per day when a pipeline arrives in 2013.

"By mid-2014 we will have 470 MMcf per day of take-away capacity to accommodate our program in this play," Best said.

Comparing these numbers with total company-wide production for 2010, "That is clear evidence of the significant impact the Eagle Ford can have on SM Energy and the opportunity we see in front of us in this play. It's a pretty exciting time for us," said Best.

Analysts at Tudor, Pickering, Holt & Co. agree. "Our review of a handful of wells that have flowed without constraint in the Galvin Ranch area shows productivity as good as offset operators," with 1.1 Bcfe of cumulative production in the first six months. "The implication is as incremental infrastructure comes online, SM should be able to quickly fill the pipe."

SM exited first-quarter 2011 with almost 92 MMcfe per day of production, and expects to drill 80 gross wells (70 net) by year-end. Guidance had second-quarter production reaching 230 MMcf per day.

The Marathon-Hilcorp deal bodes well for SM's marketing of a joint venture in the acreage, reported as a 20% to 30% position, or 72,000 net acres. But most analysts predict the valuation will be about half that of Marathon's marker, around $10,000 per acre.

Subash Chandra, equity analyst with Jefferies & Co. Inc., expects the deal to be 100% carry, worth $700- to $800 million. This assumes the nonoperated acreage, two-thirds of the total, with more oil and infrastructure, fetches $12,000 per acre, and the operated receives $6,000 per acre. "Expectations for per-acre value are considerably less than Marathon's Eagle Ford deal, because much of the acreage is nonoperated and located in condensate-poor parts of the play."

Best of play

With 33,000 net acres in the condensate window of LaSalle and Dimmit counties, Carrizo Oil & Gas president and chief executive S.V. (Chip) Johnson IV said at the New York symposium, "Most people think this will have the best economics of any area of the Eagle Ford. It's extremely profitable."

The company is looking to expand its position through lease acquisitions, focusing in Dimmit, northern LaSalle, McMullen and Atascosa counties, Johnson said. The goal: to target the play where it is shallower than 10,000 feet, with some condensate but with a majority stream of oil production. "It's very hard to find more acreage here now at a reasonable price."

Nonetheless, in early June, Carrizo bolstered its position with 13,000 new acres for $1,650 per acre up front, and a total cost of approximately $5,500 per acre once carried drilling costs are factored. While it is a reasonable price compared with other recent acquisitions, "those transactions largely included more production, more delineation, greater infrastructure as well as higher EUR targets," notes Chandra.

Carrizo's first three Eagle Ford wells IP'd at more than 1,000 barrels of oil per day each on a 24-hour rate. The following two came in at 735 and 815 barrels at restricted rates. Average EURs with well expectations of 70% liquids and 30% rich gas are 400,000 barrels of oil equivalent (300 million net), with total target reserves of some 92 million barrels equivalent.

Total well costs are $7- to $7.5 million with 5,000-foot laterals and 18 frac stages, drilled into the condensate window above 10,000 feet. Finding and development costs average $23.33 per well, with a 54% rate of return at $100 oil and $4 gas.

Subsequent to the acquisition, Carrizo now runs three rigs in the Eagle Ford, up from one at the time Johnson spoke. The company borrowed one rig from its Barnett shale program, which is saturated with wells waiting on completion, to target Dimmit County. That rig will return when a purpose-built Eagle Ford rig is delivered in December. The ramp-up coincides with a $104-million divestiture of noncore Barnett properties.

"Carrizo is moving at full throttle," says Global Hunter's Bodino. "In total, Carrizo has exposure to about 90 million BOE of reserves in the Eagle Ford with about 40% on the newly acquired acreage. All-in costs, including acreage, are expected to be below $30 per BOE."

Beginning in June, the company anticipates completing three wells a month through the end of the year. It now estimates it has 230 locations on 115-acre spacing.