Boom Days In The Eagle Ford

Feb

01

Boom Days In The Eagle Ford

Steve Toon February 1, 2012

Topping a rise on Highway 181 just north of Karnes City, Texas, four Helmerich & Payne rigs stand erect in single file like exclamation points celebrating the economic boom the oil and gas industry has brought to this region south of San Antonio. These flex rigs illuminated by the rising sun are drilling for the gas- and liquids-saturated Eagle Ford shale for Marathon Oil Corp., a new neighbor that is gearing up activity in this core area following a recent major acquisition.

Marathon is flexing its muscle here after becoming an independent E&P following last summer’s spin-off of its downstream sister, Marathon Petroleum.

Following a 28-year stint with Marathon in its Wyoming operations, Keith Mingus, Marathon Eagle Ford production superintendent, says the activity and production levels, as well as the excitement exhibited by people wanting to work in the play, are unprecedented in his career. “This is a very good play. This is the most exciting thing I’ve done in my life.”

Texas longhorn cattle and rigs are neighbors amid activity in the condensate window of the Eagle Ford shale.

In just three short years, the Eagle Ford has gone from being a nascent shale-gas discovery, when natural gas prices were robust, to a full-fledged oil boom. Unlike its predecessor, the Haynesville shale, a prolific resource play where the drilling pace faltered with sinking gas prices, the Eagle Ford contains zones rich with wet gas, condensate and crude oil, more profitable commodities in today’s environment. Operators simply shifted leasing northward into these so-called liquids-rich bands paralleling the Texas Gulf Coast. Here, they found some of the best economic returns in the onshore U.S.

“It is truly the premiere oil-shale play in the U.S.,” says Kirk Spilman, Marathon asset manager for the Eagle Ford. “As far as the economics in the core of the play, it competes with any project we have in our portfolio around the world.”

Well permitting tells the tale: As of June 2011, some 2,371 permits had been issued targeting the Eagle Ford. That compares to 26 in 2008; 94 in 2009; 1,010 in 2010; and 1,241 in first-half 2011. The play has captured the industry’s attention.

Eagle Ford rigs doubled in one year, accounting for nearly half of all U.S. rig growth in 2011.

For three straight quarters, the Eagle Ford has led the charge as the fastest growing unconventional play, as measured by rigs. In fourth-quarter 2011, the Eagle Ford saw an increase of a net 17 rigs, adding 27 oil-directed rigs to offset a 10 gas-directed-rig decline, according to a Global Hunter Securities analysis. As of yearend 2011, 220 rigs were plying the Eagle Ford shale, with 149 of those seeking oil.

Notably, the Eagle Ford accounted for a full 44% of the total U.S. rig count growth in 2011, doubling rigs running from 107 to 214.

Global Hunter Securities analyst Brian Uhlmer, in a December 12 research note, said, “Of the 107 incremental rigs now drilling Eagle Ford wells, 10 operators alone account for more than 70% of growth, having added 76 rigs year-to-date.”

Yet not all acreage in the Eagle Ford is created equal, notes Wood Mackenzie in a recent study. “Production data indicate the emergence of a sweet spot in liquids-rich DeWitt, northern Live Oak and Karnes counties.” Operators in these counties are well-positioned to outperform peers, the firm notes.

Overall, the outlook for the Eagle Ford remains strong, according to WoodMac, which backs Spilman’s assertion of dominance. “We expect the play to rival the Bakken by 2015 for position as North America’s leading tight-oil producer.”

Breakout performance

H&P Flex Rig #430, drilling the Salge Kinkler #1H for Marathon Oil in Karnes County, is tripping pipe to reach its target: volatile Eagle Ford oil and condensate 11,000 feet below surface. Well economics here provide a 50% to 100%-plus internal rate of return. Most industry observers, and certainly participants here, would say this is one of the Eagle Ford shale sweet spots.

Marathon’s Spilman does. “The well results speak for themselves. The reserves that we see coming out of that portion of the play are far superior.”

Early results from the Eagle Ford attracted the company’s attention and it began accumulating acreage in the black oil window, mostly in Wilson County.

Hart Energy’s North American Shale Quarterly shows operators’ Eagle Ford positions.

In June 2011, though, Marathon created an onshore splash when it paid $3.5 billion for Hilcorp Energy Co.’s 141,000 net Eagle Ford acres and existing production, primarily in Karnes, Atascosa, DeWitt and Gonzales counties. Setting a temporary high-water mark in the play at a rich $20,000 per acre, Marathon believes it hit the bull’s-eye.

“Early movers had an advantage (on price), but being smart about where you target is equally as important. The acreage can obviously call for the price we paid,” says Spilman. “Simply stated, it’s in the core.”

With opportunities to build organically dwindling, Marathon saw the Hilcorp package as one of the last highly concentrated, contiguous positions in the core.

In addition, Hilcorp’s holdings involved significant production—7,000 barrels of oil equivalent (BOE) per day at announcement—and 100 total wells drilled and completed by closing, essentially derisking the acreage. With six rigs running, Marathon inserted its team alongside Hilcorp’s during the five months before taking title, “and we just kept running” following closing on November 1.

With the acquisition, Marathon now has approximately 300,000 net acres in the play, and it expects to average more than 30,000 BOE per day from the Eagle Ford in 2012, essentially all from the newly acquired assets. By year-end 2011, 12 rigs were running, going to 18 this year, targeting a delivery of one rig a month. Most are “blowing and going,” harvesting acreage in Karnes County on Marathon’s core Sugarloaf complex. Holding leases remains the objective.

Marathon now has approximately $1.4 billion earmarked for the play in 2012 as it ramps up, and will maintain that average spending annually over the next several years.

“It’s our largest single capex spend,” says Spilman. The company’s plans for the Eagle Ford include drilling more than 200 wells while adding two additional hydraulic-fracturing crews, bringing the total to four frac crews by midyear.

As it accelerates to maximum velocity, its targeted spud-to-spud time is 25 days, with a typical spud to total depth of 15 days. Completions involve an average 5,000-foot lateral, 15 to 17 stages and 250 to 300 feet between stages.

Well economics are strong, Spilman states. Thirty-day initial production (IP) rates ring in at 1,650 BOE per day in this condensate window (72% liquids). Estimated ultimate recoveries (EURs) exceed 965,000 barrels equivalent. Returns: 100%-plus on $85 oil and $4.50 natural gas.

Before adding Hilcorp’s assets, the company focused further north, in the black oil window in Wilson County. The economics of the gas-condensate region, however, proved far superior. “That’s why we moved down. As we got our heads around the play, it became clear that’s where we needed to be.”

Marathon continues to drill in Wilson to maintain lease obligations and for appraisal. Further south in the trend, however, on 23,000 acres of dry-gas acreage picked up in the acquisition, the company is not currently expending any rig time.

Given Marathon’s 1,850 locations, based on 160-acre spacing in the wet regions alone, Spilman sees the development timeline progressing steadily for the next five years, with a projected 2016 average rate of more than 100,000 barrels per day. If that’s not rosy enough, considering anticipated downspacing to 80 acres or less: “I see that development timeline far exceeding five years.

“This is another cornerstone asset in Marathon’s 125-year history,” he says. “It’s hard to overstate its importance.”

Doing it differently

Magnum Hunter Resources Corp. chairman and chief executive Gary Evans acknowledges that some companies are doing extremely well in the condensate window, but to him the Eagle Ford shale is all about the crude oil.

The Houston-based company holds more than 25,000 net acres in the play, all within the up-dip oil window where wells flow 95% crude. Of that, about 19,000 acres are in Gonzales and Lavaca counties, considered by analysts and the company to be one of the growing number of sweet spots, with another 3,500 in Fayette and Lee counties, and 3,300 in Atascosa. The company targets a narrow geologic graben, or trough between parallel faults, in this region with multiple natural fractures, increasing the ability to effectively stimulate the shale.

“We made a decision to stay in this trough,” Evans says. “If we get too far east or too far west, it thins out and we don’t like it. And it’s not a very wide trough to begin with.”

The strategy has paid off. Estimated recoveries from 13 wells on production have grown from the high-200,000-BOE-per-well range in early tests up to 500,000 BOE per well at present. “The more we drill, the better we get,” says Evans. “And those results will undoubtedly continue to improve.”

Evans has that confidence because the company, in tandem with service-provider Halliburton, is testing new techniques on almost every well being drilled currently. “We are a technology-driven company and trying to be better.”

Effectively geosteering the wellbore is of critical importance to Evans, and is one of the biggest mistakes made by most other operators, in his opinion. “If you’re not in the zone, you’re not going to make a good well.”

The Magnum Hunter target is limited to a 15-foot window within the lower portion of the Eagle Ford formation. Company geologists are on the job round-the-clock to keep the wellbore true, eliminating the “porpoise effect” within the lateral and preventing drilling in and out of zone. “You can’t afford three hours of screw-up,” he says. This one procedure is what gives him the most angst when conceding nonoperated control to other partners. “You’ve got to stay in zone; I can’t emphasize that enough.”

Completions, too, are being fine tuned, particularly with borrowed experience from the company’s activities in the Bakken and Marcellus shales. “We use technology and techniques we’ve learned in these other regions. A lot of South Texas producers are not active in the Bakken and they don’t have that experience within their own company. We’re doing things in the Eagle Ford nobody else does.”

Those techniques include different ways to use downhole tools in fracture stimulation, plug and perf vs. sliding sleeves, different sized sand, spacing between perforations, and methods to increase flow after the well is online.

Longer laterals and more and closer stages are examples. Earlier wells extended 3,500 feet laterally. Newer wells have 5,000- to 7,000-foot laterals, and he hopes to reach 10,000 feet, possible only because of contiguous leases. Completions now feature 20 to 25 stages versus 13 before, and are spaced at 250 feet apart, down from 310 feet spacing. And the company has moved to a larger-grade sand, a Marcellus technique.

Well results are enviable. The latest two announced wells, Furrh #2H and Kudu Hunter #1H, in Lavaca County, flowed on 24-hour IP rates of 1,270 and 1,590 barrels per day, respectively. Oryx Hunter #1H, drilled earlier in Lavaca, flowed more than 2,000 barrels per day.

“If we have a well come in at under 1,000 barrels a day, we’re very disappointed,” says Evans. “We haven’t had that in the last six or seven wells. We’re seeing better IPs, higher pressure, and initial production is holding up longer, with more frac stages closer together.” But he warns against complacency. “We want 2,000 and 3,000 BOE per day wells.”

Another successful technique lifted from the Bakken: The company puts an electric submersible pump (ESP) on every one of its wells once the flow slows after five to nine months.

“We were the first ones to do that in the Eagle Ford. We do that on our wells in the Bakken, and it’s worked great there.” All these wells eventually need artificial lift, but can be stimulated to produce 400 to 500 barrels on ESP. “That’s not a bad deal. It’s an effective method of getting oil out of the ground more efficiently, and we get a tremendous amount of real-time bottomhole flowing data.”

And efficiency is the objective. “Our goal is to try to get at least 100,000 barrels of oil out of the well within the first year, and we deem that as payout,” Evans says. “Any way we can speed that recovery up, whether it’s higher initial production rates or a lower hyperbolic decline curve, after 100,000 barrels, the rest is gravy.”

Economics in the graben are juicy: 95% IRR at $100 oil, with new EUR projections pending. Evans emphasizes the oil produced in Gonzales and Lavaca counties is sweet, commanding up to $10 over West Texas Intermediate (WTI) on average. The company currently trucks all production, about 4,000 gross barrels a day, and is exploring pipeline installations down the road.

Magnum Hunter has partnered with Hunt Oil Co. and GeoSouthern Energy Corp. in separate 50-50 joint ventures, running two operated and two nonoperated rigs. It anticipates 12 to 15 new wells drilled this year on a $50-million budget for the play.

Outside of this core area, Evans acknowledges results on its Atascosa County position—where the play is more shallow and 24-hour IPs range between 250 and 350 barrels—are less exciting than its primary play. It is not running any rigs on its Fayette and Lee county acreage yet, preferring to let offset operators test that position.

“It’s still early in the game. The Eagle Ford is definitely not all the same. We’re trying new things that we believe will get us better results.”

Altogether, Evans sees Magnum Hunter, along with its neighbor EOG Resources Inc., at the top of the heap, with the best wells. “It’s going to be a great play for many years to come. If you’re in a sweet spot, the price per acre could eventually be $50,000 to $100,000. It’s that good.”

Eagle Ford operators are busy harvesting acreage.

 

Onshore opportunity awaits

Arkansas-based Murphy Oil Corp. is an international exploration company with vast offshore drilling projects around the globe. So with a world of opportunity awaiting it, why did it set up operations in South Texas?

“Oil is the name of the game for us,” says David Wood, Murphy president and chief executive. The Eagle Ford represents a balance of opportunity with risk and reward. Combining onshore resource opportunities such as the Eagle Ford and its Canadian positions in the Montney, Seal heavy oil and Alberta Bakken that have virtually zero risk below ground, with offshore opportunities that entail some risk, is the best of both worlds, he says. “If you invest wisely on a parallel path, you will be much more predictable.”

He points to the situation in the Gulf of Mexico, where Murphy holds substantial interests. The company had fortuitously stepped onshore South Texas in advance of the Macondo oil-spill disaster in April 2010.

“If we had not been in the Eagle Ford, then our U.S. business would be deteriorating quite rapidly,” he says. “Today, we are investing substantially more money in the Eagle Ford than the Gulf of Mexico.” Within two years he expects the Eagle Ford project to outsize its Gulf of Mexico on a net-production basis.

Murphy will drive approximately $1 billion in capex into its Eagle Ford operations this year, representing about a third of its global spend and the most for a single play. “This is the time to spend it in the Eagle Ford,” he says.

With a goal to achieve 300,000 BOE per day globally by 2015, the Eagle Ford represents a significant piece of that pie chart. Murphy exited 2011 producing some 9,000 BOE per day from the Eagle Ford. It is projecting to exit 2012 at 15,000 barrels, 30,000 barrels per day by the end of 2013, and to achieve 50,000 barrels by year-end 2015.

“It’s a high level of expenditure and a high level of rig activity that will result in attractive growth over the next five years. On a percentage basis, that’s pretty good year-on-year growth.”

The company currently holds over 250,000 gross acres up and down the play, acquired for an average of approximately $1,700 per acre, with a target of getting to 300,000 acres if economic opportunities arise. It will focus activity on 18,900 acres in Karnes County, where it is most active now, 46,400 acres in Dimmit County (the Catarina project), and 73,400 acres in Atascosa County (the Tilden project).

About half of its total position is in the crude oil and liquids window of the play, with the bulk of the rest in the dry-gas area.

Six rigs were running at year-end, with plans to ramp up to 12 rigs by the second half of this year, and level there. “We can get everything done we need to do at that level of rig activity.”

The Karnes project in particular, its easternmost Eagle Ford acreage, has exceeded expectations. At the outset, using ambient data, Wood anticipated IPs at 500 barrels per day and EURs around 550,000 barrels. “All of the wells we’ve done since we sanctioned the area have done quite a bit better that that,” he says.

In fact, estimated recoveries exceed 750,000 barrels per well, approaching 1 million in some. On IPs, Murphy chokes the wells initially at 500 barrels, believing that produces a flatter decline, “but the individual wells would produce two or three times that.”

Dimmit wells are different, however. At the western front, the formation is shallower and the wells come on producing 100% water for about 30 days as the wells clean up following completion, before flowing 300 to 500 barrels of oil per day. “The Eagle Ford is not homogenous,” he emphasizes. Nonetheless, Wood says the company has not drilled a disappointing well across its holdings. “We don’t have anything we would cross out of a map and say it’s no good.”

As of mid-December, Murphy had drilled 53 Eagle Ford wells, at a cost of close to $8 million per well, with 40 producing. In Karnes County, where most of its activity is focused and holding leases is not an issue, Wood considers the well data to be sufficient to begin development drilling. For Murphy, that involves drilling four wells per pad, typically, on 160-acre spacing currently. “We’ll end up going down to spacing below 80 acres,” he acknowledges, with some already tested.

Murphy is manufacturing wells with 3,500-to 4,500-foot laterals and 12 to 15 stages, a recipe “that seems to be working about right,” says Wood. The company is maximizing efficiencies by moderating horsepower and the amount of product pumped into the ground, as well as reusing frac fluids.

Infrastructure capacity has alleviated somewhat, reducing the amount of oil it was trucking that is now shipped via pipeline. Likewise, where associated gas recently had few outlets, “that’s less of an issue now. Access is becoming better and better every day.”

Crude is sold to local refineries and marketers in South Texas, and currently is receiving premiums near $5 to WTI. Its associated gas, rich in liquids, receives a price well above the Henry Hub benchmark.

Although the Eagle Ford is not the best play Wood has experienced, he likes the U.S. fiscal regime, low-density and industry friendly population, easy access and resource potential that it offers. “It’s not the best place in the world, but it compares favorably. I should have gotten 600,000 acres at the outset when it was $100 an acre.”

Still, this year and beyond, it will dominate Murphy’s budget. “For the next five years it will be one of our main liquids growth drivers in our company.”

Doubling down

Pioneer Natural Resources Co. is entrenched in the vertical Permian Spraberry trend as the largest acreage holder and producer there with a growing opportunity in the horizontal Wolfberry play. But the Eagle Ford shale, quite a few Texas counties southeast, is gaining similar stature for the Dallas-based independent as a prime liquids growth asset.

“We’re spending a large sum of money on infrastructure and will probably drill more than 100 wells” in 2012, says Tim Dove, Pioneer president and chief operating officer. Gross drilling costs are expected to be approximately $700- to 800 million, before a joint-interest partner carry. In June 2010, Reliance Industries of India bought a 45% interest of Pioneer’s then 212,000 net Eagle Ford acres, excluding other zones. Reliance paid $1.15 billion, of which $266 million was cash up front, and another $880 million was drilling carry. To date, about 40% of the carry remains and will be deployed in 2012.

The company spent 2011 building its rig fleet, doubling rigs running in the play from six to 12, with plans to add more this year. Production has grown from essentially zero to 360 million cubic feet equivalent (MMcfe) per day since the joint venture with Reliance.

Pioneer currently holds approximately 130,000 net acres, with activity concentrated in the condensate and wet-gas zones of DeWitt, Karnes and Live Oak counties. Rigs are focused on lease preservation, with two-thirds presently held by production. Thirteen wells drilled during the third quarter averaged 2,270 BOE per day IP and yielded 65% liquids, including oil, condensate and natural gas liquids (NGLs).

“The areas where we’re drilling are some of the best in the overall Eagle Ford shale play,” Dove says, “specifically in DeWitt County.” Here, the liquids-rich gas is deeper, at 12,000 to 13,000 feet, and higher pressured, “so there is a large amount of energy in the system that leads to more productivity per well and higher EURs.”

Pioneer uses a blended average 6-billioncubic-feet (Bcf) type curve, but Dove quickly emphasizes the curve shifts significantly from north to south, moving from dry to wet zones, and from east to west as depth and pressure change. Add to that the variation in rock quality up and down the trend.

“This play has a tendency to have sweet spots,” he notes. And while some 20% of Pioneer’s total acreage falls in the dry-gas window, “we’re heavily focused on our liquids-rich area, where we’re seeing very strong performance.”

Rosetta Resources Inc. believes it has fully delineated 50,000 acres in both the condensate and oil windows, an anticipated $5-billion project. Senior vice president of asset development John Clayton says, “This is going to generate significant cash flow for many decades.”

A standard Pioneer completion features a 5,500-foot lateral with 13 stages. “We’ll be testing longer laterals through time where the lease configuration allows it.”

The company is also testing cluster orientation and reducing spacing between stages, and has completed five wells using Schlumberger’s HiWAY frac. Results are still pending. Early on, Pioneer settled on gel-conveyed fracs when pumping ceramic proppant, with up to 50% better results.

At $7 million to $8 million per well, the economics return a sweet 80% before-tax IRR on high-condensate-yield wells, and 60% for lean-condensate-yield wells ($90 oil, $5 gas), before the JV carry benefit.

To reduce well costs, two of three dedicated frac fleets are Pioneer-owned and operated, the second added in December, as well as two coiled-tubing units. This saves approximately $1.7 million per well, Dove estimates. “It gives us a tremendous advantage,” he says. “You’re talking a dramatic reduction in costs considering the number of wells we’re drilling.”

Further, the company is testing switching from ceramic proppant to white sand in certain well stimulations, particularly in the shallower, less-pressured areas of its holdings, reducing the frac price tag by $700,000. The technique has been tried in 20 wells, showing similar well performance to direct-offset ceramic-stimulated wells. Dove anticipates white sand will be used in about 30% of wells going forward.

A legacy player in the dry-gas Edwards trend underlying much of its Eagle Ford position, Pioneer takes pride in having recognized early the lack of infrastructure in the region to handle associated liquids production from the wet-gas stream. It is proactively beginning to build out processing capacity. It now has eight central-gathering facilities in place with about 500 MMcf per day of processing capacity, with plans for 13 total central gathering facilities within two years.

“That puts us way ahead in terms of processing and stabilizing our liquids,” he says. In fact, the company has excess capacity and is processing third-party gas.

Condensate and crude are still trucked while awaiting a new Enterprise Products Partners’ pipeline coming online the middle of this year. “That will move all of our liquids and handle increased production needs. With our trucking and pipeline contracts in place, we’ve had essentially no infrastructure-related issues.”

Dove adds, “This shale play has proven to be prolific. You’ll see a substantial ramp-up as we accelerate in this field. We’ll be drilling wells here for a long time to come.”

Rosetta’s bloom

The 26,500-acre Gates Ranch, spanning Webb and Dimmit counties in far South Texas between Carrizo Springs and Laredo, is known as a white-tail deer hunter’s paradise, but to Houston independent Rosetta Resources Inc., it is paradise for different reasons.

“Gates Ranch is our crown jewel,” says John Clayton, Rosetta senior vice president of asset development. Rosetta has drilled and completed 62 wells here and has not missed on a single one. Rich in condensate, these wells pay out in just eight to 10 months, and 300 drilling locations remain.

Clayton estimates some 12 trillion cubic feet equivalent of hydrocarbons underlie the position, about 300 Bcfe per section. “The net present value of that asset is tremendous for our company,” he says.

The Eagle Ford shale comprises 93% of Rosetta’s 2012 budget, making it virtually a pure player aside from an anticipated exploratory position in the Alberta Bakken shale play. Beyond the ranch, Rosetta also holds 23,500 acres in the oil window, and another 15,000 dry-gas acres, amounting to a 65,000-acre Eagle Ford position overall.

“We believe we have fully delineated 50,000 net acres in the condensate and oil windows.” Clayton estimates the capital investment to develop the delineated acreage to be $5 billion. “Keep in mind that’s coming from a company with a market cap of half that. This is going to generate significant cash flow for many decades.”

Gates Ranch is now in full development mode. Drilled with three per pad, wells here average 10- to 12 MMcfe per day, with a 10-Bcfe EUR. These results are being delivered on 5,500-foot laterals with 15 frac stages, the optimized geometry for the geography. Early completions took eight days using the plug-and-perf method; today’s completions pump three wells and 45 stages in just seven days.

“It’s resulted in tremendous cost savings. We’re saving $1.2 million to $2.5 million per pad on those three wells.”

Completion fluids, too, have evolved to a combination slickwater with a small part gel—and the company has downsized its per-stage volumes. “We’re getting the same results we were getting early on when we put in more mass,” Clayton confirms. Also, intermediate-grade proppant has proven a better value at Gates Ranch, where Eagle Ford depth is at 8,000 feet.

“We’ve made the conscious effort to put the investment up front so that when reservoir pressure decreases and the overburden increases, we’ve got enough conductivity down there to get maximum production out of these wells.”

Well spacing, too, has doubled the prize. Early on at Gates Ranch, Rosetta began testing well spacing from 400 feet apart to 850 feet. After two years of online production, “we do not believe we are seeing any drawdown greater than 200 feet from the wellbore,” notes Clayton. “We feel comfortable that a good balance between commerciality and reservoir drainage makes sense at roughly 65-acre spacing.”

Rosetta decided to tackle the spacing question early in the life of the field to be able to maximize pad-drilling efficiencies. The strategy of infill drilling later didn’t appeal to the company for other reasons. “We don’t believe it’s the optimal way to do it. We believe operators will experience operational problems when they try to drill in between two producing wells and then stimulate those wells.”

Like Magnum Hunter, Rosetta geosteers its wells into the lower part of the 250-foot-thick Eagle Ford. Logs indicate higher resistivity here, thus more hydrocarbons, and cores show the lower portion of the zone is more ductile, while the upper zone is brittle.

“When we initiate the frac in the lower Eagle Ford, it will have a tendency to be more efficient as it grows upward and fracs the more brittle rock. That has helped us place proppant across the entire vertical interval,” Clayton explains.

Beyond Gates Ranch, Rosetta likes its oil-window prospects. Three recent well results look promising. One well in DeWitt County tested at 3,000 BOE per day (89% liquids) on a seven-day IP rate. Two others in Dimmit County produced at 1,990 BOE (67% liquids) and 680 BOE (89% liquids) per day.

“Our oil-window areas have exceeded our pre-drill expectations, and that includes declines,” he says. “We’ve yet to see large declines.”

For dry gas, Rosetta has successfully renegotiated leases to extend an additional three years, and plans no such drilling activity in its current budget.

In late fourth-quarter 2011, the company added a fourth rig and plans to hold steady at that level this year with a 60-well development pace. That amounts to an 11-year inventory with 650 locations. Two rigs will plow Gates Ranch, with the others developing the oil-window properties. That level of activity will amount to a 40% year-over-year production growth. Production at year-end 2011 was 175 MMcfe per day from the Eagle Ford, up from less than 10 MMcfe per day two years ago.

Now past a bump in third-quarter take-away capacity, the company assures it is moving all produced volumes with no constraints. Current firm capacity is 216 MMcfe per day, going to 331 million by early 2013. John Hagale, Rosetta executive vice president and chief financial officer, says, “We’re in good shape for volumes coming in the next year and a half.”

For 2012, Rosetta will spend about $595 million in the play, up from $400 million in 2011. Its Eagle Ford program should be self-funding by year-end, the company predicts. Until then, Rosetta notes it has the liquidity to meet the challenge while staying within a 30% debt-to-capitalization ratio, and would only consider a joint venture if it were on the buying side.

How does Clayton rate the Eagle Ford? “I would stack it up against any play in the Lower 48,” he says. “As far as repeatability, dependability and commerciality, I can’t see any that have a higher rate of return and a lower cost structure than what we’re seeing in the Eagle Ford. We wish we had about five of these.”