The Eagle Ford Shale play cuts a wide swath from the Texas border to San Antonio, and the high fliers are gathering around the play’s sweet spot in the multipay zone Maverick Basin.

Companies are flocking to the area to acquire property, acquire other operators, and provide funds for farm-in deals and joint ventures.

Among the majors, ConocoPhillips seems to hold the strongest position with its 300,000 acres of leases, but other majors want in on the action, too.

A Houston Chronicle report in April 2010 quoted a Shell executive who said his company had purchased 150,000 acres in the play, but the executive didn’t reveal the name of the seller, the price paid, or the part of the Eagle Ford acquired.

By mid-March 2010, the industry was talking about rumors that BP had signed a joint venture agreement with Maverick Basin veteran Lewis Energy to work some 80,000 acres prospective for Eagle Ford and other zones. Neither BP nor Lewis confirmed the rumor.

Even though majors were late getting into the big US shale plays, they’ve entered the shale game, not only in the United States, but throughout the world.

They’re looking particularly at shales such as the Eagle Ford, which, in some parts of the play, offer a bonus of high liquids content.

Anadarko Petroleum Corp.

Anadarko Petroleum Corp., one of the top shale operators in the United States, reinforced that foundation with a major presence in the Eagle Ford Shale in South Texas.

Anadarko is a large company with a multitude of highly prospective projects onshore and offshore. It can choose the prospects that make the most economic sense and, within the limitations of obligations to drill, it can direct considerable resources to those prospects. Among the shales, it has chosen the Marcellus, Haynesville, Eagle Ford, and Pearsall.

Coming into 2010, the company held approximately 350,000 gross acres of land in the Maverick Basin and had encouraging results from wells in both the Eagle Ford and the deeper Pearsall Shales. It claimed some 6 Tcfge in gross unrisked resource in the Eagle Ford. That compared with the company’s gross unrisked resource of more than 30 Tcfge in the Marcellus Shale and some 9 Tcfge in the Haynesville Shale.

According to a TXCO Resource Inc. presentation, TXCO had a quarter share in that property with 1.5 Tcfge in potential production. St. Mary Land & Exploration Co. held another quarter share.

Early in 2010, the importance of the play for Anadarko rose dramatically as Anadarko bid $310 million to buy out bankrupt TXCO’s Maverick Basin properties, beating an earlier bid by Newfield Exploration.

That deal later changed to joint buyout by Newfield and Anadarko. The two companies kept the $310-million bid, but agreed to split the properties.

In that deal, Anadarko paid approximately $93 million in February 2010 for more than 80,000 net acres to increase its working interest in the properties to 75%. Newfield planned to pick up the majority of TXCO’s assets, more than 350,000 gross acres with production of some 1,500 boe/d. Two-thirds of that production was liquids.

In a March 2009 presentation, TXCO said it had 725,000 gross, 442,000 net, acres in the Eagle Ford along with an existing pipeline infrastructure.

It claimed 7 Tcfge to 10 Tcfge in net recoverable resource figuring 80 Bcfge to 110 Bcfge throughout 489 net sections.

The properties, XTO said, gave the company approximately 1,950 drilling locations on 160-acre spacing, and it had about the same potential in the deeper Pearsall Shale play. It estimated a recovery factor of about 20% of the in-place resource, or 16 Bcfge to 22 Bcfge per section.

As early as the first quarter of 2009, Anadarko had drilled its first Eagle Ford well. That well tested at rates as high as 6 MMcfge/d with high liquid content. It drilled a total of approximately 15 wells in the Eagle Ford and Pearsall Shales 2009.

According to IHS Inc., Anadarko staked the 1H Worthey Ranch in Webb County, Texas, about 20 miles west of Encinal. It planned to drill the well to 10,000 ft on a 5,470-acre lease and completed the well in the Eagle Ford as part of Briscoe Ranch Field.

A month earlier, it had permitted the 1H Stanley Ranch a mile and a third to the northeast. It scheduled that horizontal well to 12,000 ft measured depth, with a bottomhole location about a mile to the northwest.

In late February 2010, IHS reported, Anadarko had 11 Eagle Ford wells – either permitted or reissued – and five recent completions in its Briscoe Ranch Field in Dimmit County, Texas.

Among the completions, the company completed the 4H Briscoe Catarina West for 310 b/d of condensate and 1.1 MMcf/d of gas, according to IHS. Calculated absolute open flow for the well was nearly 3.2 MMcf/d of gas.

It drilled that horizontal well to 12,064 ft with Helmerich & Payne’s Rig 248, reaching total depth on Nov. 14, 2009, just 19 days after the spud date. It fractured the well between 8,490 and 12,064 ft in 14 stages using 113,848 bbl of frac fluid and 1,607 tons of sand.

Antares Energy Ltd.

Antares Energy Ltd., an Australian company, opened its US operations as a pure Eagle Ford Shale player working the emerging South Texas fairway. According to Antares, that decision has “dramatically impacted on the company’s value.”

It currently has four core projects: Oyster Creek, West Wharton, Yellow Rose and Shaeffer Ranch, with varying interests and venture partners. For example, Shaeffer Ranch is a joint venture that holds a three-year lease on 7,400 acres.

Its Bluebonnet Project included an 87.5% working interest in 5,754 acres with a best estimate of 298 Bcfge in proved and probable reserves.

It held a 75% working interest in 18,274 acres in the Yellow Rose project with a best estimate for proved and probable reserves of 840 Bcfge.

Yellow Rose and Bluebonnet combined hold a potential inventory of more than 300 wells.

Yellow Rose in McMullen County has a 75% interest in the Frances Dilworth No. 2H. San Isidro Development Co. is the operator.

The partners completed that well in January 2010 for 790 b/d of oil and 900 Mcf/d of gas with 4,500 psi of flowing tubing pressure through a 22/64-in. choke. Adjusting for the 1,300-Btu gas, initial production was 15.4 MMcfge/d.

Based on that success, the companies made plans for the No. 3H and 4H wells and Antares reached an agreement with Nabors Industries for a rig to drill nine horizontal wells at Yellow Rose during 2010. It may elect to keep the rig for another 10 wells in 2011 and beyond. By the end of 2012, it anticipated holding all its Eagle Ford acreage in the project by production.

The company’s year-end-to-year-end closing share price rose 1,141.5%.

In a February 2010 presentation, Antares held more than 32,500 acres of Eagle Ford Shale properties with a low-risk, three-year inventory of prospects with locations for more than 35 wells.

In early 2009, Antares sold rights in 5,102 gross, 4,840 net, acres of land prospective for Eagle Ford to Petrohawk Energy Corp. Antares retained a working interest in wells drilled on the property after payout on a well-by-well basis, and Petrohawk agreed to drill the first well within a year of the agreement. Those properties are immediately south of the Yellow Rose area.

Overall, on its Eagle Ford properties, Antares expected to pay $5 million for a well completed and tied to a sales line, and it anticipated ultimate recovery of 5.5 Bcfg per well on the allowed temporary field spacing rules of eight wells per section.

Apache Corp.

Apache Corp. picks its plays carefully throughout the world and in North America. Its onshore North American unconventional properties include the Granite Wash in the Texas Panhandle, the Horn River Basin shale play in British Columbia, and the Eagle Ford Shale in South Texas.

The company held 200,000 acres in the Granite Wash and claimed 17 MMcf/d of gas and 800 b/d of liquids from its first horizontal well in that play in late 2009. It had been drilling vertical wells.

It held another 221,625 acres of land in the Ootla area of northern British Columbia in cooperation with EnCana Corp. Apache was an early entry into that play and started its operations there in 2001.

The company also claims highly successful operations offshore northwestern Australia and in western Egypt. It is also the biggest producer from shallow water in the Gulf of Mexico.

With plenty of other prospects on the corporate plate, the company has its 450,000 acres of Eagle Ford properties on hold.

According to Steven Farris, president and chief executive officer, quoted in a Seeking Alpha report in late 2009, “We have a pretty good acreage position in there presently. We have about 450,000 acres through the oil side and some in the gas side. In fact, we’re re-looking that. We’re not drilling a well at the present time. We’re re-looking pressure and core analysis to try to figure out . . . We drilled a horizontal well that was a very marginal well, frankly, on the gas side.”

The company has no Eagle Ford wells in its budget for 2010.

In a 2008 analyst review presentation, Apache said its Eagle Ford properties were in Burleson County. It reported the Giesenschlag-Groce 2H tested for an initial potential of 305 b/d of oil after a nine-stage hybrid fracture treatment with 1.33 million pounds of sand.

At that time, Apache was acquiring additional acreage in the play and conducting extensive analysis on its wells. It acquired multiple cores, drilled grass-roots horizontal wells with increasingly long laterals, optimized fracture treatments, continued its learning curve, tested different areas in the play, and monitored the economics of the play.

As it has with its other onshore plays, Apache planned cost-saving techniques such as multi-well pads, multi-well facilities, central mud puts for the multiwell pads, re-use of flowback water for fracture treatments and lower concentrations of potassium chloride in the frac water. Those modifications could save 20%, or $1.6 million, per well.

At the time of the 2008 analyst review, Apache said the current well cost was $8.1 million and, on a well with 100,000 bbl in reserves, it would need an oil price of $138 to break even. A 20% reduction in well cost would lower that break-even price to $108, and a 40% cost reduction would set the break-even point at $81 per barrel.

Apache picked up most of its Eagle Ford properties through an arrangement with Enervest Ltd. Enervest already had 425,000 acres of properties in the prospect area held by production from other zones. Under the agreement, Apache could earn the deeper rights in the area by drilling wells during 2009.

According to Apache, even considering a 50% productive area, its Eagle Ford properties would generate 700 potential locations on 320-acre spacing.

It estimated reserve potential from the area at 105 million boe, assuming 150,000 boe per well for 700 wells.

On the optimistic side, the properties could cover a potential 315 million boe in reserves with 1,400 wells on 160-acre spacing and 225,000 boe per well. In some parts of the Eagle Ford play, 160-acre spacing is standard.

Aurora Oil & Gas Ltd.

Aurora Oil & Gas Ltd. of Perth, Australia holds substantial interests in properties in the United States, including leases in the Sugarkane Field area of the Austin Chalk-Eagle Ford play.

The field covers more than 200,000 acres, and Aurora’s portion of that is divided into three areas of mutual interest: the Sugarloaf AMI, in which Aurora has a 20% working interest, or 23,498 gross, 4,780 net, acres; the Longhorn AMI, in which the company owns a half interest, or 23,763 gross, 11,881 net, acres; and the Ipanema AMI, in which Aurora holds an 80% ownership interest, or 4,430 gross, 3,624 net, acres.

Netherland, Sewell, and Associates Inc. assigned Aurora’s portion of that field’s proved and probable reserves of 391 Bcf of gas and 72 million bbl of liquids before the company’s farm out of a portion of the property to Hilcorp Energy Co. the fourth-largest, US-based, privately held exploration and production company.

Aurora farmed out its consolidated interests throughout Sugarkane field. In return, it will be carried for a significant work program that will give the company an interest in up to 10 producing wells in the field. That includes seven new wells and stimulation treatments on three existing wells.

Hilcorp Energy Co. can earn up to half of Aurora’s interests in the acreage in the Sugarloaf and Longhorn AMIs and five-eighths in the smaller Ipanema AMI.

By January 2010, 15 wells had been drilled into the Eagle Ford in the field, four in Aurora’s area of interest, and the remaining 11 by ConocoPhillips on adjacent properties.

Among the four wells in which Aurora has an interest, the Sugarloaf #1 vertical well has been suspended, but retained as a future sidetrack option.

The Kennedy #1H, with a 4,000-ft horizontal section, is producing with limited stimulation across the bottom 600 ft.

The Kowalik #1H, with a 4,600-ft horizontal section, is producing from slotted liner with no frac treatments.

The Weston #1H, with a 3,000-ft horizontal section, has the liner cemented in place and is awaiting stimulation and completion.

On Feb. 8, 2010, Aurora said Hilcorp had exercised its right under the farm-out agreement to assume operatorship of the Sugarloaf AMI.

It also said the company’s new Easley #1H had reached 11,350 ft with intermediate casing cemented and drilling proceeding to the Austin Chalk and Eagle Ford with a vertical pilot hole before drilling the horizontal section.

Fracture treatments were started on the existing Weston #1H’s 3,000-ft horizontal section.

The existing Kennedy #1H was cleaning up after stimulation and was producing at an initial potential rate of 4.4 MMcf/d of gas and 1,130 b/d of condensate. Hilcorp planned to install producing tubing.

Common Resources LLC

Common Resources LLC is not so common. The company started operations with $500 million in stake money from EnCap Investments L.P. and Pine Brook Road Partners, LLC, and a proven management team that included Roger Jarvis, former chief executive officer of Spinnaker Exploration, and Elliott Pew, former executive vice president of Newfield Exploration.

It started by targeting formations along the Gulf Coast, West Texas, and parts of the Midcontinent, particularly plays in which it could wring maximum benefits from horizontal drilling.

Along the way, it built a position of 48,675 gross, 36,918 net, acres in the Eagle Ford play with potential for production in both the Pearsall Shale and the Edwards Lime.

The company estimated a net resource of 1 Tcfge with 491 well locations in the Eagle Ford trend. It spent $55 million to drill six wells in 2009 and planned to spend another $61 million on eight to 10 wells in 2010 — all in the Hawkville District in La Salle and McMullen Counties.

Among operations to date, the company completed the 2901H South Texas Syndicate well 15.2 miles southeast of Los Angeles, Texas in La Salle County in November 2009. The horizontal well spud on July 13, 2009, and finished completion operations on Nov. 4, 2009. The development well tested for 155 b/d of condensate, 11.6 MMcfg/d of gas, and 1,050 b/d of water from perforations between 11,650 and 16,452 ft. Calculated absolute open flow was 22 MMcfg/d.

In the same area about 20.2 miles southeast of Los Angeles, Common drilled the 1H Nueces Minerals Co. 20 — another development well. It spud that well on May 21, 2009, and completed it on Sept. 13, 2009. That horizontal well tested for 8.7 MMcf/d of gas and 1,840 b/d of water through a 26/65-in. choke with 4,015 psi of flowing casing pressure following a multistage frac job. The well produced from perforations between 12,972 to 17,119 ft. Calculated absolute open flow on the well was 14.6 MMcf/d of gas.

ConocoPhillips Co.

ConocoPhillips commands operations around the world — upstream and downstream — in nearly every kind of activity — from exploration to retail sales; from partnerships with large companies to lone-wolf projects — and it chose the Eagle Ford shale as one of its Lower 48 operations in the United States.

It is already the largest oil and gas producer in North America at 1.1 million boe/d, 5.1 million boe in proved reserves, and 29.6 million net acres of properties.

Its Lower 48 properties extend from the Bakken Shale in the north to the Lobo Trend in southern Texas, and from the Uinta Basin in the west to the Black Warrior Basin in the east.

It is the largest producer in the San Juan Basin with 400 MMcf/d of gas from the Fruitland coalbed methane seam and another 700 MMcf/d of gas from tight sands.

Now the company has taken a 300,000-acre position in the Eagle Ford Shale — more than its combined acreage in the Bakken (180,000 net acres) and the Barnett (110,000 acres) Shales — according to the company’s 2009 presentation to analysts.

The Bakken, Barnett, and Eagle Ford Shales top the company’s priority list in the Lower 48 states onshore.

In the company’s third quarter 2009 conference call, Sig Cornelius, senior vice president of finance and chief financial officer, talked about the company’s Bordovsky A-7 well in the Eagle Ford. “We had it on line for a relatively short period of time, but we are very encouraged,” he said. “We’ve got a flow rate of nearly 4 MMcf/d (of gas) but, more importantly, around 1,500 b/d of condensate. So that has been part of our strategy, to focus on plays that have very high XX—these shale plays that have a very high liquid content obviously very important on the economics.”

ConocoPhillips has also been “entertaining some offers for potential farm-out of our position, but we are not going to farm it out unless we see a compelling value proposition. So far, we have not seen that,” he added.
At that time, the company was running one rig in the Eagle Ford.

Jim Mulva, chairman and chief executive officer, added, “It started with Burlington (ConocoPhillips acquired Burlington Resources in 2005). They got into this position, and we have continued to access and get more acreage at a pretty low price over the last several years before it really developed into promise. We have money in our exploration program that we can really ramp up what we see as the opportunities in Eagle Ford, and we have also been doing a lot of seismic work and technology work. It just looks a lot more promising to us. And, as Sig said, if we part with some acreage, it is going to be on a lot better terms than we thought even recently.”

The company said little about the Eagle Ford in its plans for its $4.1 billion exploration and production budget for 2010 in the North America. It did say it will prioritize spending on the highest-graded production opportunities, including the San Juan and Permian Basins and the Bakken, Lobo, and Barnett trends.

It also said, “The company also plans to progress exploration drilling in the Eagle Ford Shale position in the US Lower 48, a coal seam gas play in China, and a shale gas play in Poland.”

Mulva, talking about the company’s 2009 operations, said only, “In the Eagle Ford Shale play, we have seen encouraging drilling results and are pleased with our large acreage position.”

According to an IHS Inc. report on oil and gas operations in the United States, ConocoPhillips — which still operates some of its properties under the Burlington name — said Burlington staked a horizontal wildcat 4.5 miles northeast of Runge, Texas in southwestern DeWitt County, Texas.

The 2 Butler A-304 was scheduled to Cretaceous at a total depth of 14,500 ft with a bottomhole location less than a mile to the southeast with planned completion as a part of Sugarkane Field.

This was an offset to the 1 Butler A-304 drilled by Burlington in the summer of 2008 to 13,573 ft and plugged back to 13,479 ft. That well was still awaiting completion tools.

The sole Sugarkane Field producer in DeWitt County was the 1 Hooks, completed in the Cretaceous several miles to the northeast in May 2009. That well flowed 718 Mcf/d of gas and 155 b/d of condensate from perforations between 13,739 and 18,525 ft. That would put the well below the Eagle Ford, Buda, and Del Rio Formations.

Overall, Sugarkane Field had 12 active wells in Live Oak and Karnes Counties, most operated by Burlington. They gave the company a cumulative production Eagle Ford and Cretaceous of 1.65 Bcf of gas and 328,947 bbl of condensate since the field came on stream in 2006.

El Paso Corp.

El Paso Corp. executives are re-forming the company, converting it from a developer of onshore and offshore conventional plays to an operator firmly planted in expectations of higher gains from unconventional onshore resources while holding onto its cash cow pipeline operations. The plan is working.

"El Paso is finishing one of its best years ever operationally," said Doug Foshee, chairman, president, and chief executive officer, as he reviewed the company’s guidance for 2010. "Our pipelines continue to execute extremely well on the construction of our committed backlog while developing new opportunities for future growth, such as the Marcellus Shale. Our E&P business has had an excellent year, as domestic operations have exceeded expectations with the advancement of our Haynesville, Eagle Ford, and Altamont programs. We enter 2010 with excellent momentum, and during our investor and analyst meeting today, we will touch on the robust outlook we have for the next several years."

The company divested its Gulf of Mexico properties in 2008, and accelerated its activity in the Haynesville and Eagle Ford Shales and the Altamont oil play in Utah in 2009.

In keeping with the philosophy of building for future growth, El Paso is concentrating on its most economic and most repeatable plays, according to a December 2009 analyst presentation. To that end, it planned to spend $1.1 billion on exploration and production in 2010. Exploration and production in the United States will use $900 million of that total, and expansion in the Haynesville and Eagle Ford Shales and Altamont oil will use half of the domestic allocation.

It entered the Eagle Ford play in 2009, put together 132,000 net acres of leases and planned to maintain a one-rig program during 2010.

Overall, El Paso held an estimated 4.9 Tcfge in risked unproved inventory, and 45% of that inventory lay in the Haynesville and Eagle Ford Shales. To prove up those plays, it planned to invest about $62 million in the Eagle Ford in 2010 and about $240 million in the Haynesville.

The company said it could break even in the two shale plays with a gas price of $3.90/Mcfge.

The company said its first completion in the Eagle Ford — a well with a 4,000-ft lateral and a 16-stage frac job in La Salle County — produced between 7 MMcfge/d and 8 MMcfge/d after cleanup. Its existing properties represented a risked resource potential of 1.1 Tcfge (2.2 Tcfge unrisked), about the same as the company’s potential in the Haynesville. That number assumed half its acreage contributed to the total.

Its property held 700 potential drilling locations, but El Paso planned a 10-well program during 2010. It also planned to continue to acquire land in the plan and further delineate its acreage position. Most of the company’s properties are in the dry gas area of the Eagle Ford play in Webb and La Salle Counties, but it had some leases in the condensate window in La Salle County.

EOG Resources Inc.

EOG Resources Inc. likes plays where it can put its experience and technical talent to work to generate high returns at low costs. Although the Eagle Ford doesn’t rank high on the company’s list of favorite plays, it does hold a place in the corporate portfolio and it fits the company’s preference profile.

Parts of the Eagle Ford generate liquids-rich gas, while other parts are in the oil zone. Both fit the company’s hybrid-play preference for low-permeability reservoirs that require horizontal development for highest returns.

As in straight gas plays, reserves in those wells increase and costs decrease with experience, the company said in a January 2010 presentation.

“Returns across the board are attractive at current oil prices — much better than either deepwater Gulf of Mexico or Canadian oil sands,” the company said about its hybrid plays.

Even during that presentation, however, EOG did not list the Eagle Ford among its important plays. Among gas shales, it listed the Horn River Basin shales of northern British Columbia, and the Barnett, Marcellus, and Haynesville in the United States.

In South Texas, the company’s priority plays were the Frio, Wilcox, and Lobo/Roleta trends as worth mentioning.

Still, the company holds properties in the Eagle Ford, and it is working the play.

The company permitted the 4H Harper Unit on a 640-acre lease as part of Eagleville Field in north-central Karnes County, Texas, about 13 miles northeast of Karnes City, Texas. It proposed a total depth of 12,000 ft in the horizontal well with the horizontal leg reaching to the northwest.

It also permitted the 8H Harper Unit three-quarters of a mile to the west-southwest, also to 12,000 ft. Other horizontal Eagle Ford tests included the 1H, 2H and 3H Harper units, according to IHS Inc.

The Eagleville Field opener was the 1 Milton — a 13,166-ft discovery by EOG in June 2009. That well flowed 112 b/d of oil, 131 Mcf/d of gas, and 28 b/d of water from fractured Eagle Ford Shale perforations between 11,056 and 12,870 ft.

The company also set production pipe at the 3H Milton Unit — a horizontal wildcat — also in the Eagleville Field area. It also permitted the 2 Milton and the 4 Milton units.

IHS also said the company permitted the 100H Tully C. Garner — a horizontal Eagle Ford development well scheduled to 11,000 ft in the Hawkville District 1 Field.

Escondido Resources II LLC

Escondido Resources II LLC, formed in December 2004, assembled more than 80,000 net acres of properties in the Maverick Basin in South Texas and drilled more than 150 gas wells with a 95%-plus rate of success.

Those wells were in the shallow Escondido and Olmos sands. It sold its assets in September 2007 to Swift Energy Co., but the management team stayed intact and formed Escondido Resources II LLC with the help of capital from EnCap.

The new company stayed in familiar territory in the Edwards, Olmos, and Escondido Formations in McMullen, La Salle, Webb, and Dimmitt Counties in South Texas — property that also had potential for production from the deeper Eagle Ford zones.

The company later increased its position in the area with the acquisition of 17 producing wells in northern Webb County from Kaiser-Francis Oil Co. Those Olmos and Escondido wells sat on 2,300 gross acres of land.

At the same time, Escondido acquired 40,000 new gross lease acres in Webb, La Salle, and McMullen Counties. Those properties also were prospective for Olmos and Escondido Formations, but they also were perspective for the Eagle Ford Shale.

In all, the company has about 60,000 gross acres in the Eagle Ford trend. It has participated in seven Eagle Ford wells in La Salle County and drilled its first operated Eagle Ford well. It planned a 21-stage frac treatment in a 5,600-ft lateral within the 300-ft-thick Eagle Ford section.

Espada Operating LLC

Espada Operating LLC, a smaller independent, works the Eagle Ford play in McMullen and Zavala Counties in southern Texas. As a privately held company, Espada doesn’t report the extent of its properties or the results of its activities.

In McMullen County activity in January 2010, the company spud the 1H Furie-La Jolla in Hawkville District 1 Field using Orion Drilling Rig #6.

It projected the horizontal well to 17,000 ft on an 8,156.24-acre lease at a location 15.5 miles southeast of Tilden, Texas, according to IHS Inc. This is a tight hole. The company didn’t plan to release drilling details or results.

Espada permitted three recent wells in Zavala County. Among them, it planned the 1H Chaparrosa “B” development well in Chittim Field. It projected that well to Eagle Ford at 6,000 ft. The well is located on a 640-acre lease some 19.5 miles northwest of Crystal City, IHS said.

EV Energy Partners LP

EV Energy Partners LP (EVEP) holds properties from the San Juan Basin in the west to the Appalachian Basin in the east and has a big stake in the success of the Eagle Ford play.

The company bought properties in the Austin Chalk play in June 2007, and added more properties in June and September of 2009.

In all, EVEP accumulated approximately one million acres, had access to more than 1,300 well bores, and was running two drilling rigs in the shallower zones, according to a January 2010 presentation. The properties produced more than 17 MMcfge/d.

The earlier acquisitions paid off as the partnership said the company and institutional partnerships managed by its parent, EnerVest Ltd., entered a multiyear exploration joint venture in which they farmed out more than 400,000 acres of land owned by EVEP and EnerVest to Apache Corp. That farm-out included zones below the Austin Chalk.

Under the agreement, EVEP and EnerVest contributed the acreage and supporting data and Apache operated the deeper zones.

“This is an exceptional deal of EVEP, EnerVest, and Apache. Apache is an excellent exploration company, and we are excited about working with them and added value from the additional exploration and development of the deeper potential of this acreage,” said John B. Walker, chairman and president of EVEP.

Under the agreement, Apache was obligated to spend $30 million on the properties over four years. According to Walker, Apache spent that money in the first year as it worked three drilling rigs in the oil-prone portion of the Eagle Ford play. One well produced some 500 b/d of oil.

In EVEP’s fourth quarter report, recorded by Seeking Alpha, Walker said, “Apache is not drilling in the Eagle Ford currently. They have had some modest results in the Eagle Ford but really very good results in the Georgetown. And so, in terms of us not putting up any money, we are receiving some revenues from that. And, I think that as time goes by — Apache — they’ve given us indications that they will be drilling in the gas leg of the Eagle Ford, since their focus previously has been in the oil leg of the Eagle Ford.”

Exxon Mobil Corp.

Exxon Mobil Corp. has taken a hard, close look at gas shales since the Barnett play exploded in northern Texas; and that look includes at least a glance at the Eagle Ford in southern Texas.

According to a Houston Chronicle article, the company has properties with Eagle Ford potential in La Salle and McMullen Counties, but details about activity on those properties are tight.

The company’s exposure to gas shales showed up in 2006 when it acquired 11,000 acres of land in the Barnett play and started drilling six wells under a joint venture agreement, with Harding Co. of Dallas to test the formation in northern Tarrant and southern Johnson Counties where Harding already had 25 Barnett wells.

It was 80% owner of a venture group called DDJET LLP, named after Dallas, Denton, Johnson, Ellis, and Tarrant Counties, but the group also had properties in Collin, Hill, and Navarro Counties. The group also bid on Dallas-Fort Worth Airport properties.

In June 2008, analyst Michael Lynch at Gerson Lehrman Group said, “The company (ExxonMobil) is reviewing all of its producing properties in Europe and has recently signed participate agreements with MOL (Hungarian Oil and Gas Plc.) and Falcon Oil and Gas (Canada) to evaluate shale gas reservoirs in Hungary.”

The clearest step in ExxonMobil’s move toward gas shales was the company’s bid late in 2009 to acquire shale giant XTO Energy Inc. for $41 billion.

If that bid succeeds, that would give ExxonMobil 380,000 acres in the Fayetteville Shale producing 100 MMcfge/d, 160,000 acres in the Woodford Shale producing about 70 MMcfge/d, Haynesville properties producing 45 MMcfge/d, 277,000 acres in the Barnett producing 622 MMcfge/d, and 280,000 acres in the Marcellus Shale, according to XTO’s third quarter 2009 report.

Some Eagle Ford properties may also join that list. In response to a question during a second quarter 2009 conference call about the company’s interest in the Eagle Ford in La Salle County, XTO Chairman Keith Hutton said about the Eagle Ford, “We’re watching it real close. We do have some acreage there. I’m not really ready to talk about it. We have done some re-completions in some other wells and they look fine. So, we’ll probably bounce into that play eventually and start talking about it, but not at this time.”

Hilcorp Energy Co.

Hilcorp Energy Co. — the fourth-largest, US-based, privately held oil and gas exploration and production company — took over operating duties in early 2010 on a farm-in position in the Eagle Ford Shale.

Aurora Oil & Gas Ltd. of Perth, Australia held significant positions in three areas of mutual interest (AMIs) in the 200,000-acre Sugarkane Austin Chalk-Eagle Ford play.

It held 23,498 gross, 4,780 net, acres in the Sugarloaf AMI, 23,763 gross, 11,881 net, acres in the Longhorn AMI, and 4,430 gross, 3,624 net, acres in the Ipanema AMI.

Those properties had contingent resources totaling 391 Bcf of gas and 72 million bbl of liquids, according to a Netherland, Sewell and Associates, Inc. survey.

Aurora farmed out its consolidated interests throughout Sugarkane to Hilcorp for a carried interest in a program expected to give Aurora interests in seven new wells and three existing wells that needed fracture treatments. Under the agreement, Hilcorp can earn up to half of Aurora’s interests in the Sugarloaf and Longhorn AMIs and five-eighths of the smaller Ipanema AMI.

Also, under the agreement, Hilcorp could opt to become operator of the wells. It exercised that option in February 2010. It also had started working on its commitment in the program.

The Kennedy #1H, with a 4,000-ft horizontal section, was producing with limited stimulation across the bottom 600 ft.

The Kowalik #1H, with a 4,600-ft horizontal section, was producing from slotted liner with no frac treatments.

The Weston #1H, with a 3,000-ft horizontal section, had the liner cemented in place and was awaiting stimulation and completion.

Aurora also said the company’s new Easley #1H had reached 11,350 ft with intermediate casing cemented and drilling proceeding to the Austin Chalk and Eagle Ford with a vertical pilot hole before drilling the horizontal section.

Fracture treatments were started on the existing Weston #1H’s 3,000-ft horizontal section.

The existing Kennedy #1H was cleaning up after stimulation and was producing at an initial potential rate of 4.4 MMcf/d of gas and 1,130 b/d of condensate. Hilcorp planned to install producing tubing.

Laredo Energy LLC

Laredo Energy LLC has worked the multiple pay zones of South Texas. Since its formation in 2001, Laredo has used its experienced management team to register consistent successes on its properties in South Texas.

The company's managers have worked the area since 1982 with a history of more than 300 wells. Laredo continued to drill 20 to 30 wells a year in the area and has sold most of its assets in South Texas three times. Those properties were in areas prospective for Eagle Ford Shale production.

The company and working interest partners sold properties producing 30 MMcfe/d with 196 Bcfe and reserves and undeveloped properties to Chesapeake Energy Corp. in 2003 for US $200 million. Chesapeake bought another parcel of 41,000 gross, 38,400 net, acres with 40 MMcfe/d of production in 2005 for $369 million.

The company sold a third parcel — this 27,000 gross, 23,000 net, property — to El Paso Corp. for $255 million. That parcel produced 19 MMcfge/d and 84 Bcfe of proved reserves.

Since that time, the company assembled another 200,000 gross, 115,000 net, acres with financial backing from EnCap Investments L.P. and Avista Capital Partners.

An April 2010 press release from Meritage Midstream Services, which had signed a contract with Laredo to install a 48-mile high-pressure gas pipeline, said Laredo held 120,000 acres in Webb County alone.

Laredo was drilling for conventional gas on most of those properties. In early 2010, it had 26 producing wells in Webb and Zapata conventional zones and an inventory of 60 proved, probable, and possible locations, with another 130 non-operated wells in Mecom Ranch Field in Zapata County, five wells in East Seven Sisters Field in Duval County, and 75 non-operated wells in AWP Field in McMullen County. AWP Field also was prospective for Eagle Ford production.

Among completions, Laredo found conventional pay in the Wilcox, Lobo, Escondido, Austin Chalk, Olmos, and Navarro Formations.

The company's Laredo Energy IV Limited Partnership was drilling unconventional wells in northern Webb County in early 2010, according to a company presentation.

The presentation showed Laredo Energy acreage with Eagle Ford potential toward the southwestern end of the play near the border, with Mexico interspersed with Eagle Ford properties held by EOG Resources Inc., Swift Energy Company, Rosetta Resources Inc., El Paso, and Escondido Resources II L.L.C.

IHS Inc. statistics showed only one well completed in the Eagle Ford among Laredo Energy's 62 active wells and the limited partnership’s three active wells. That was the Rosa V. Benavides 2H well. It drilled that well 18.8 miles northwest of Laredo. That horizontal development well reached total depth at 15,526 ft and was waiting on completion tools in April 2010.

According to Glenn D. Hart, president and chief executive officer, “South Texas is a great place to have a natural gas business, particularly in Webb and Zapata Counties. We look forward to continuing to grow Laredo Energy in this vibrant area for many years to come.”

Lewis Energy Group

Lewis Energy Group, through its Lewis Petro Properties affiliate , holds substantial properties and is the most active producer in Webb, La Salle, and Dimmitt Counties in Texas — an area that includes some of the most active Eagle Ford Shale exploration and production operations.

Although the private company didn’t itemize its properties in the area, it has been drilling and producing from the bread-and-butter Olmos Formation in the Encinal area for more than a quarter of a century.

The company owns its own drilling rigs and has shown consistent growth under Rod Lewis, president, chief executive officer, and founder.

Its activities are not restricted to the Olmos, and some of the company’s land — held by production — is prospective for deeper Eagle Ford Shale.

In recent activity, the Texas Railroad Commission completed the 1H Storey 267 in Hawkville District 1 Field in La Salle County. The company drilled the horizontal well to the Eagle Ford at 15,435 ft in eight days in June 2009, about 19 miles southeast of Cotulla. The discovery well tested for about 313 b/d of condensate, 5.4 MMcf/d of gas, and 626 b/d of water from perforations between 11,245 and 15,316 ft.

In the same area, the company had Hawkville District 1 Field permits for the 1 Golla 7H, the 1H Martin Family, the 1H Lyssy Family, and the 3 Appline 716H, according to IHS Inc. records.

In other La Salle County activity, Lewis completed the 1 Evans H in the field 6.5 miles southeast of Artesia Wells using its own drilling rig. After a multistage fracture treatment, the well tested for 68.5 b/d of condensate, 3.4 MMcf/d of gas, and 409 b/d of water through a 32/64-in. choke with 945 psi of flowing tubing pressure and a calculated absolute open flow of almost 4 MMcf/d of gas. It produced through perforations between 10,509 and 14,201 ft.

In addition to several permits issued in Webb County, Lewis Petro Properties completed the 2B Booth Unocal H in Big Reef Field about 39 miles north of Laredo. That well tested for 43.4 b/d of condensate, 4.4 MMcf/d of gas, and 449 b/d of water from Eagle Ford perforations between 9,712 and 13,229 ft through a 20/64-in. choke with 2,584 psi of flowing casing pressure. Calculated absolute open flow on that well was 12.4 MMcf/d of gas, according to IHS.

The company’s activity hasn’t always centered on its home counties. A January 19, 2004 article in the San Antonio Business Journal said Lewis Energy was contracted by Mexican state oil company Pemex to produce 40 MMcf/d of gas for the next 20 years from the Olmos Block in the Burgos Basin, immediately south of the US-Mexican border. Lewis contracted to invest $340 million in the project with a return to be paid from production.

Modern Exploration Inc.

Modern Exploration Inc. of Sherman, Texas, drilled most of its wells in the Barnett Shale, but it successfully drilled its first Eagle Ford well in July 2009.

The independent started operating in March 1977 and has drilled most of its wells in Texas. It specializes in southern Texas where it has its own experts. If the company finds a promising prospect in another part of Texas or the country, it relies on experts in those areas to work up the geology.

Modern’s first Eagle Ford well, the 1 Texas Two Step, is located in Gonzales County about 8.8 miles southeast of Gonzales, Texas, according to IHS Inc.

Actually, it is a re-completion of the company’s Austin Chalk well with the same name. It completed that well in 1993.
In the re-drill, it targeted the Eagle Ford at 15,000 ft. The company spud the well on July 24, 2009, reached total depth at 11,935 ft on Aug. 18, 2009, and released the drilling rig two days later. In December 2009, the well still was flowing frac fluid back to the well bore.

Murphy Oil Corp.

Murphy Oil Corp. doesn’t take on many onshore plays, and some 85% of its activity occurs outside of North America, but the company has set its sights on the Eagle Ford Shale as a play that can meet its return requirements.

Murphy completed its first Eagle Ford Shale well in January 2010. That discovery well, the George Miles 1H in McMullen County, reached a vertical depth of 13,320 ft and then turned horizontal for another 3,190 ft. Murphy completed the well with a 13-stage frac job and read the gauges that showed an initial potential of 7.5 MMcf/d of gas.

“We are very pleased by the results of our first well in this promising Eagle Ford Shale play and by the quality of the acreage we have accumulated. We are currently drilling our second well in Karnes County to evaluate another tranche of our leasehold and expect to stay very active in this play throughout the year,” said David M. Wood, president and chief executive officer.

In a November 2009 presentation, Wood said the company had started an initial three-well evaluation program in the Eagle Ford. At that time, the company planned to retrieve cores and carefully evaluate the formation’s characteristics. It spud its first well in August 2009.

Murphy has more than 100,000 acres on land in Dimmitt, La Salle, McMullen, Atascosa, Live Oak, Karne,s and Bee Counties in southern Texas.

During the company’s fourth quarter 2009 report, recorded on Seeking Alpha, Kevin Fitzgerald, senior vice president and chief financial officer, said, “In 2009, we’re very active in acquiring leases, especially in the Eagle Ford Shale, but for 2010 will be much more tilted toward exploration drilling activity.”

At that time, Wood said the company was “moving on towards 200,000 leased acres” in the Eagle Ford. He also said, after the company ran tubing, the production rate on the George Miles well climbed to 11.7 MMcf/d of gas, and the company connected the well to a sales line at a rate of approximately 4 MMcf/d of gas. That rate would improve when the company moved the water out of the well, he added.

In that February 2010 presentation, he said the company had reached total depth on its second well, the 1H Drees “A-179” in Karnes County, and the drilling rig was setting up to drill the Oasis Mineral Company MOH well in La Salle County.

Murphy also added a second drilling rig in the play with a start up time in mid-February 2010.

“We’ve really only drilled two wells and only flow tested one well, but we’re in a great location with our acreage in La Salle and McMullen County, where we have over 100,000 aces in the key part of the play as we see it,” Wood said, and added, “I think you can get our acreage and risked, of course, another 3+ Tcf. So that’s kind of how I break it down in getting towards that 10 (Tcf). Again, the upside of down spacing exists in both these plays (including the Tupper area of western Canada).”

The first three wells the company drilled in the Eagle Ford were expensive, he said, because the company is drilling the wells to cover the full section. The well and the frac job to complete the well cost slightly more than $13 million.

The first well had a 3,190-ft lateral, but the second well will drill laterally for 5,000 ft. That longer reach equates to more frac stages.

Murphy also permitted the 1H Crescent C in Hawkville District 1 Field and the 1H Nueces Mineral Co. in La Salle County. It projected the Crescent well to 13,000 ft in the Eagle Ford. It has permitted three wells in McMullen County.

Newfield Exploration Co.

Newfield Exploration Co. executives set the company up for a significant position in the emerging Eagle Ford Shale play as it bought most of the Maverick Basin properties of TXCO Resource Inc., currently working its way through the bankruptcy procedure.

Newfield likes large-scale unconventional plays. In a February 2010 presentation, the company said it held 166,500 net acres with 300 operated wells in the Woodford Shale in Oklahoma. It planned to put four rigs to work in the Granite Wash in 2010, and it had a joint venture with Hess Corp. to work the Bakken Shale in North Dakota.

At that time, the company said it had interests in most of the major plays in Texas, including South Texas.

In a third quarter 2009 conference call with analysts, recorded by Seeking Alpha, executives said the company had about 10,000 acres in a South Texas field that produced from the Edwards Formation but also was prospective for Eagle Ford. At that time, Newfield was considering exploratory work in the Eagle Ford.

In November, Newfield and Anadarko Petroleum Corp. jointly announced their participation in a $310-million deal to acquire TXCO’s core Maverick Basin assets. Anadarko’s part of that deal amounted to more than 80,000 acres at a price of $93 million to raise its working interest in the properties to 75%.

Newfield received approval by the bankruptcy court in mid-February 2010 to get more than 350,000 gross, 300,000 net, acres and some 1,500 boe/d of production for about $217 million.

Newfield got the properties for around $723 an acre. That’s a bargain for promising Eagle Ford land, considering Petrohawk Energy Corp. paid about $3,000 an acre for prime land with Eagle Ford potential in the more heavily drilled Hawkville Field in McMullen County.

The TXCO properties are on the western portion of the play in Maverick, La Salle, Zavala, and Dimmit Counties.

Lee K. Boothby, president and chief executive officer of Newfield, said, "This acquisition is consistent with our goal of focusing on large, domestic plays of scale. Including this transaction, we have added more than 500,000 net acres in long-lived resource plays over the last several months. Our acquisition of TXCO’s assets will mark an entry into the Maverick Basin and provide us with a deep inventory of potential locations — both oil and gas. We have been active in South Texas for more than a decade and our people have a proven track record of success. We will ensure that our team is focused on the right assets in this region to create long-term value for our shareholders. We expect to have an active drilling program in 2010."

The Eagle Ford is not the only formation with promise in the area. The Maverick Basin offers some 20 formations that have produced hydrocarbons.

Anadarko had earlier bid $310 million to take all of the properties.

Before its bankruptcy court filing in May 2009, TXCO was working on three major projects in the basin: the Eagle Ford-Pearsall shale play, the Glen Rose oil play, and the San Miguel heavy oil sand play.

The company’s Briscoe Catarina West 1H tested for 6 MMcfge/d from the Eagle Ford.

In a March 2009 presentation, TXCO said it had 442,000 net acres in the basin that were prospective for Eagle Ford Shale. It estimated 7 Tcfge to 10 Tcfge in recoverable resource with 80 Bcfge to 110 Bcfge per section in its 489 net sections of land. It also claimed more than 1,950 net drilling locations, figuring 160-acre spacing.

Petrohawk Energy Corp.

Petrohawk Energy Corp. is an imposing force wherever it chooses to operate, and the Eagle Ford formation joined those locations with the company’s discovery well for Hawkville Field in late 2008.

At that time, the company held 160,000 net acres in the play. Since then, it has grown at a fast pace in acreage, in production, in reserves and in aspirations.

In the company’s 2009 operations update, presented in February 2010, Petrohawk reported total proved reserves of 2.75 Tcfge within a potential resource of 31 Tcfge.

It held 157,000 net acres in the Fayetteville Shale, 360,000 net acres in its core Haynesville Shale and 122,000 acres in the Bossier Shale.

It also held 210,000 net acres with 2,700 drilling locations, 288 Bcfge in proved reserves, and 8.5 Tcfge in resource potential in the Eagle Ford Shale. Some 207,000 of those net Eagle Ford acres were undeveloped, just in Hawkville Field. In addition to the Hawkville properties — mostly in La Salle and McMullen Counties — the company owned the Red Hawk prospect in Zavala County to raise total holdings in the play to 310,000 net acres.

For comparison, Petrohawk’s average leasehold cost in the Haynesville Shale was $5,000/acre with an average estimated ultimate recovery of 7.5 Bcfge/well and an average initial potential of 18 MMcfge/d of gas. That play produced 500 Bcfge/d at the end of 2009, and the company operated 17 drilling rigs.

The average leasehold cost in the Eagle Ford was $400/acre with a 90% average working interest, average estimated ultimate recovery of 5 Bcfge to 6 Bcfge/well, a well cost of $4.5 million to $5 million, and an average initial potential for the 22 wells it had drilled to that point of 10.4 MMcfge/d. It was working four rigs in that play.

The Haynesville will remain the company’s top priority but, according to the update, it expected Eagle Ford drilling to increase, relative to the Haynesville, by 2012.

Petrohawk added the Red Hawk prospect during 2009. In Zavala County, the Eagle Ford is at 5,000 ft, compared with approximately 11,000 ft in McMullen and La Salle Counties. The company had a $4-million leasing commitment there and spud its first well in December 2009.

Also during 2009, the company added 294 Bcfge in proved reserves through the drill bit as it drilled 24 wells and participated in two additional non-operated wells. By February 3, 2009, the company had just completed its second well in the play.

Petrohawk also added to its position through an agreement to jointly developed 26,000 acres in Hawkville Field in McMullen County owned by Swift Energy Co. Under that agreement, Petrohawk paid $26 million to Swift. It would operate the wells and carry Swift for $13 million in costs during the first 12 months of the contract. Swift would retain a half interest in the properties. That deal covered all formations below the Olmos, including the Eagle Ford.

Early in the company’s participation in the play, Petrohawk said it found a trend of increasing condensate in the Hawkville area from southwest to northeast. Results ranged from no condensate in the Dora Martin #1H to 110 bbl of condensate per million cubic feet of gas from the Donnell #1H some 30 miles to the north.

The two wells showed total organic content between 4.4% and 4.7%, total porosity between 9.4% and 10.7%, average permeability between 1,110 and 1,280 nanodarcies, gas saturations from 83% to 85%, and an estimated range of free gas of 180 Bcf and 210 Bcf per section.

Later, it said, the first three wells in the play all were drilled with pilot holes, hole cores, and intermediate casing set, and took 53 days from spud to rig release. The fourth well, with no pilot hole and with intermediate casing set, took 32 days to drill to total depth. The fifth well, drilled the same as the fourth, took 22 days to total depth. A new design allowed the company to avoid setting intermediate casing in the future, the company said.

Pioneer Natural Resources Inc.

Pioneer Natural Resources Inc. made a name for itself in many of the plays in which it has worked, and it’s approaching that reputation in the Eagle Ford Shale.

The company pioneered a deepwater play in the Western Gulf of Mexico and later sold it, but its primary claim to fame is its Spraberry operation in West Texas. It has been the primary operator in the Spraberry for years and led the charge to the Texas Railroad Commission acceptance of downspacing in the play, a move that doubled the company’s well locations.

Now, Pioneer is the biggest producer in the biggest producing field in the Lower 48 states. Spraberry Field produced 153,000 boe/d in mid-2009, according to Scotia Waterous. It was followed by Wattenberg Field in Colorado at 133,000 boe/d and Midway-Sunset and Belridge South Fields, California, each with 96,000 b/d. At 46,000 boe/d of production, Pioneer is by far the biggest producer in the Spraberry.

Now, it has the Eagle Ford firmly in its sights. The company has 310,000 gross acres of land in South Texas, most of it accumulated while it was putting together an Edwards play beneath the Eagle Ford formation.

It drilled its first horizontal well in the play, the Friedrichs Gas Unit #1 in DeWitt County, was completed in mid-2009. That well showed an initial potential of 2.7 MMcf/d of gas and 160 b/d of condensate, but the well had mechanical problems and the company only completed five of the planned eight stages of the fracture treatment, or less than 500 ft of the planned 3,000-ft lateral section. It doesn’t count that as a successful well.

Pioneer’s first successful well, the Sinor Ranch #5 in Live Oak County, tested for 8.3 MMcf/d of gas and 500 b/d of condensate in October 2009. That well reached a 13,000-ft total vertical depth and added a 2,600-ft lateral with a nine-stage frac treatment.

Its second successful well, the Robert Crawley #1 — about 2.5 miles to the southeast — tested for 17 MMcf/d in January 2010. It reached a total vertical depth of 14,000 ft and produced from a 5,400-ft interval after a 16-stage frac treatment. Those two wells convinced the company to expand its Eagle Ford drilling program in 2010.

After drilling more than 150 operated wells in the area, primarily to the Edwards, Pioneer has an advantage over newcomers to the play. It chooses its drilling sites with the help of more than 2,000 sq miles of 3-D seismic data and logs from those drilled wells. It also has proprietary core samples and results from micro-seismic activity during frac operations.

The liquids-rich portion of the Eagle Ford play offers another big advantage. It produces 1,200 Btu/Mcf gas.

In other words, a dry gas well producing 11.7 MMcf/d of gas gives a return of $57,000 a day. The Sinor Ranch #5 produced 500 b/d of condensate for $35,000 a day, 790 b/d of natural gas liquids for $28,000 a day, and 6.6 MMcf/d of gas for $33,000 a day for a total of $96,000 a day.

Put another way, a liquids-rich Eagle Ford well testing at 11.3 MMcfge/d gives the company the revenue stream of a 19.2 MMcfg/d well, Pioneer said.

In addition to the company’s fourth quarter 2009 production of 60 MMcfge/d from South Texas and from existing and potential production from Eagle Ford, Pioneer still has some 200 optimized Edwards locations on its property.
The company also permitted the 1 Handy in Karnes County. That horizontal wildcat is scheduled to 19,000 ft, according to IHS Inc., bottoming a mile to the northwest of the surface location.

The company’s success led it to form an Eagle Ford Shale Asset Team to focus operations in the area.
In a February 2010 presentation, Pioneer said it was considering working with a joint venture partner in the play, and it anticipated bids in the second quarter of 2010.

Rosetta Resources Inc.

Rosetta Resources Inc. plunged into the Eagle Ford play as it stood by its two-year business model to shift from a conventional player to a resource play “with a focus on inventory, inventory, inventory.”

In a February 2010 presentation, the company asked analysts to look for significant growth in Eagle Ford during the year.

By that time, the company had accumulated 52,000 net undeveloped acres in the play area with potential for 325 wells and an unrisked potential to tap 975 Bcfge in reserves.

During the third quarter of 2009, Rosetta drilled and completed its second horizontal well in the play, the Gates Ranch 05D #9-5H in northwestern Webb County. It drilled to 8,300 ft total vertical depth and turned into a 3,700-ft lateral section. A week after pipeline hookup on Oct. 6, 2009, the company produced 3.5 MMcf/d of gas, 337 b/d of oil, and 548 b/d of water through a 24/64-in. choke. The gas measured 1,320 Btu/cf. That well is in the company’s Gates Ranch Field where it holds more than 12,000 net acres.

It previously discovered the Springer Ranch #1H in southwestern La Salle County, where the company accumulated 14,000 net acres in the Springer Ranch area.

IHS Inc. also permitted the 102 Gates Ranch “05-D” in Webb County. Success at that well would extend Hawkville Field to the south. The company planned to drill to a total depth of 9,500 ft.

In La Salle County, the company permitted the 3 Springer Ranch with plans to drill a development well in Hawkville Field 3.4 miles northwest of Encinal.

During 2010, Rosetta will ramp up its Eagle Ford activity with three rigs running through the year. Two rigs will do development work and the other will handle exploration.

Rosetta’s top priority will go to acreage offsetting its Gates Ranch discovery in the condensate window of the play.

San Isidro Development Co.

San Isidro Development Co., founded by Blackstone Dilworth, president, chairman, and owner, also conducts drilling operations in South Texas with the Eagle Ford as one of its prime targets.

It also works as operator for other companies, Antares Energy Ltd. of Australia, for example. Antares is working its Yellow Rose project in McMullen County with a 75% interest in area wells. San Isidro, as operator, completed the Frances Dilworth No. 2H in January 2010 for 790 b/d of oil and 900 Mcf/d of gas with 4,500 psi of flowing tubing pressure through a 22/64-in. choke. With adjustments for the 1,300 Btu/cf gas, the well produced 15.4 MMcfge/d.

It also permitted the Frances Dilworth No. 3H and 4H horizontal wells and contracted with Nabors Industries for a rig to drill nine horizontal wells with San Isidro as operator during 2010. It can elect to keep the rig for another 10 wells in 2010 and beyond.

San Isidro also is an Antares partner on the Bluebonnet project about four miles north of Yellow Rose. San Isidro also is operator in that project with a 12.5% working interest.

Both the 3H and 4H wells were projected to 11,500 ft some 7.9 and 7.3 miles, respectively, southwest of Tilden, Texas.

By February 2010, Antares held more than 32,500 Eagle Ford acres.

St. Mary Land & Exploration Co.

St. Mary Land & Exploration Co. set a goal to become a recognized North American resource play company by the time tested technique — using legacy assets for cash flow and drilling funds and acquiring substantial positions in developing and emerging plays.

Among the steps to reach its goal, St. Mary has put together 5.1 Tcfge in resources in those emerging plays, including the Haynesville, Marcellus, and Eagle Ford Shales.

It accumulated 225,000 leased or option acres in the Eagle Ford, including 159,000 net acres in its own high-working-interest acreage and another 66,000 net acres in a joint venture with TXCO Resource Inc. and Anadarko Petroleum Corp.

In December 2009, the company said it added a second rig on its own Eagle Ford properties in November, and it completed the St. Mary-operated wells in Phase 2 of the joint venture. The venture partners were moving ahead with Anadarko-operated wells.

Among the company’s wells to date, it completed the Galvan Ranch 1H to a vertical depth of 8,500 ft with a 5,000-ft lateral and a 17-stage frac job. The well produced at a seven-day maximum rate of 8 MMcfge/d. It also completed the Galvan Ranch 4H to a vertical depth of 9,100 ft and a 5,000-ft lateral with a 15-stage fracture treatment. That gave the company a seven-day maximum production rate of 7 MMcfge/d. Pipeline constrictions later curtailed production on that well.

The Galvan Ranch wells in the southern part of the fairway produce dry gas with no condensate, while wells farther north increase in condensate content.

Also on its acreage, St. Mary drilled the Briscoe Apache Ranch 1H to 7,900 ft vertically and added a 4,000-ft lateral and a 14-stage frac treatment. That well produced at a maximum seven-day average of 7.1 MMcfge/d. The Briscoe G 1H, tested for a maximum seven-day average of 6.4 MMcfge/d and a maximum 30-day average of 4.1 MMcfge/d. That well produced 1,300 Btu/cubic ft gas with 48 bbl of condensate per thousand cubic feet of gas.

It was also drilling or completing the Briscoe G 2H, the Briscoe G 3H, the Briscoe B 1H, and the Galvan Ranch 7H wells.

St. Mary also permitted the 1H San Ambrosia “B” horizontal well less than a mile northeast of the US-Mexico border and about 50 miles northwest of Laredo, Texas. The well could be completed as part of Briscoe Ranch Field.

St. Mary started operations in the Maverick Basin in the second half of 2007 when it finished two acquisitions to get into the Olmos shallow gas play. It knew about the potential of the deeper Eagle Ford and Pearsall Shales at the time.

Tony Best, president and chief executive officer, said, “Our 2010 capital program reflects the expansion and improvement in our inventory over the past couple of years and gets us back on a track of growing production. We will be deploying a meaningful amount of investment in our emerging resource plays, particularly in the Eagle Ford and Haynesville Shales as we work to promote those potential resources to proved reserves.

The company will continue to operate two drilling rigs in the Eagle Ford play on its high-working-interest properties in Webb, Dimmitt, and La Salle Counties. The company already has improved drilling efficiency. Its first well took 45 days to drill. Its latest well took only 14 days, the company said.

It plans to spend 78% of its investment in the Eagle Ford to drill 34 gross operated wells. It will have a 100% interest in most of those wells. Much of the work will de-risk untested parts of its lease holdings and developing liquids-rich gas areas.

It will put approximately $47 million into the joint venture properties in the northern part of the play, and it will spend some $24 million on infrastructure expansion.

Texon Petroleum Ltd.

Brisbane, Australia-based Texon Petroleum Ltd. entered the Eagle Ford play like many others — by delving into deeper zones from the shallow Olmos gas play.

Texon controls leases that include the Eagle Ford in Leighton Field, where it has potential for seven wells and 1.8 million boe with a half working interest.

In an August 2009 presentation, the company said it also had an Eagle Ford land position in Mosman Field that would yield the same potential as Leighton.

By including all available producing formations, Texon has 30 possible well locations at Leighton on 40-acre spacing — the same spacing as another operator has in an adjoining field.

The company planned to deepen either its Leighton 3 or Leighton 4 well to test the Eagle Ford to test the 1,200 aces under Leighton Field with Eagle Ford potential. The presences of oil and gas at Leighton also would suggest petroleum is present under the 1,234 acres in nearby Mosman Field, the company said.

Since that time, the company combined the Rockingham prospect with Mosman for 3,269 acres.

In a January 2010 release, Texon said it planned to begin drilling its Mosman-Rockingham #1 well in late February, some five miles south of Leighton Field. It planned to drill to 11,200 ft to test both the Olmos and Eagle Ford reservoirs.

Texon previously drilled the Tyler Ranch #4 in Leighton Field to the Eagle Ford Shale and found 142 ft of oil and gas shows with similar characteristics to Hawkville Field some 12 miles to the southwest of Mosman-Rockingham.

The company added, just one Eagle Ford well that produced at the same rate as Petrohawk’s average well in Hawkville Field, about 13 MMcfge/d, would more than double Texon’s current production.

Tidal Petroleum Inc.

Tidal Petroleum Inc. zeroed in on South Texas as its primary area of operations. The company has become expert in working prolific plays in the region since it was founded in June 1990, and it has added the Eagle Ford to its inventory of prospective formations.

According to the company’s web site, it chose this region because it contains some of the most prolific reserves in the United States, and it lends itself to the company’s operating philosophy; “Our focus leans toward deeper drilling programs containing multiple producing horizons in order to decrease the risk of dry holes and increase longevity of production life.”

Among its traditional targets, the Frio and Vicksburg sands from 3,000 to 5,000 ft offer shallow gas, low unit costs and excellent economics.

At mid-depth, the Hockley, Yegua, and Pettus sands from 5,000 to 7,000 ft can contribute both oil and gas and contain large reserves.

At deeper levels — with Wilcox Sand from 8,000 to 10,500 ft — in the right places, gives up high daily production from high reserves.

IHS Inc. lists one permit in the Eagle Ford by the company during 2009. It proposed to re-enter the 1 Los Cuatros in Hawkville Field about 8 miles east of Eagle Pass, Texas, with a horizontal well to the Eagle Ford. The previous well, completed in 1978, tested for 170 Mcf/d of gas from Lower Cretaceous perforations between 6,562 and 7,600 ft.

Union Gas Operating Co.

Union Gas Operating Co. was drilling to the Eagle Ford Shale as part of the company’s continuing operations in southern Texas.

The company re-entered the Acock Operating Ltd. 1H Franklin Murray Estate well in McMullen County 12.2 miles northwest of Tilden, Texas. That well reached oil and gas pay in the James Lime. The new horizontal well, named the 1H Fox Creek Ranch, initially targeted to shallow Olmos Formation in AWP Field, but later was projected to 9,800 ft as a horizontal Eagle Ford well in Hawkville Field.

The company spud the new well with Helmerich & Payne’s Rig #182 on December 5, 2009, and was still drilling in late January 2010.

The company also has drilled Frio wells in DeWitt County and Wilcox wells in Lavaca County — both counties are prospective for Eagle Ford.

Vanguard Natural Resources LLC

Vanguard Natural Resources LLC purchased its way into potential Eagle Ford production by acquiring oil and gas properties to one of the biggest operators in southern Texas.

The company closed its first acquisition from an affiliate of Lewis Energy Group L.P. in Webb County, Texas in July 2008. That acquisition consisted of 91 producing wells and an approximate 45% interest in 1,700 undeveloped acres of properties. That acquisition gave the company 20 Bcfge of proved reserves, 65% proved producing, and 98% of that production was gas. Lewis remained as operator of the wells.

The second acquisition, also from the Lewis affiliate, occurred in July 2009. That acquisition included some 27 Bcfge of proved reserves, 94% gas, and 74% proved developed. The properties were producing 5 MMcfge/d at that time. Lewis also continued to operate those properties.

The latter properties were on the Olmos Trend in Dimmitt, La Salle, and Webb Counties — counties which also cover the deeper Eagle Ford formation. Specifically, the producing properties were in Dos Hermanos Field in Webb County and Sun TSH Field in La Salle County.

Under the latter agreement, Vanguard paid $52.3 million in cash, and Lewis would operate the producing properties and drill seven wells a year on the undeveloped acreage through 2015, according to a January 2010 Vanguard presentation.

Additional opportunities were available, the company said, as Lewis monetized its mature assets to focus on the Eagle Ford Shale.

At that time, Lewis was the largest operator in the Olmos Trend with some 1,100 operated wells and 50 MMcfge/d of net production.

At the time of the 2009 acquisition, Scott W. Smith, Vanguard president and chief executive officer, said, "We are very pleased to be able to announce this transaction with Lewis, our South Texas operating partner. When we closed our initial South Texas acquisition last summer, we indicated one of our goals was to add additional assets through subsequent acquisitions as Lewis looked to monetize mature assets to fund their exploration efforts. With an enviable leasehold position in the emerging Eagle Ford Shale play, this transaction provides Lewis the opportunity to monetize a small percentage of its assets to provide capital for an exciting exploration opportunity.”

WEJCO Inc.

WEJCO Inc. put up a small Eagle Ford prospect property position in the Karnes County, Texas, for possible farm-in by an industry participant in a horizontal completion.

The company planned to drill the Eagle’s Talon prospect to 14,500 ft vertically and kick off on a 3,500-ft horizontal leg.

It estimated the well cost at $1.8 million for a re-entry and $5.5 million for a new-location drilling program.

The company estimated potential reserves at 7 Bcfge per well and 35 Bcfge on its 875-acre lease. Those figures assume two re-entries and three new horizontal wells on 160-acre spacing.

Under the proposal, the farm-in participant would pay 100% of the cost of the first re-entry well through completion to earn an 85% working interest in the prospect and in the area of mutual interest on all depths below the Wilcox. WEJCO can act as operator and would be carried for 15% on that initial well. It also would be a 15% working interest partner.

The farm-in partner would reimburse WEJCO for approximately $345,000 in sunk costs at the time of the commitment to the project, WEJCO said. The company would deliver a 72% net revenue interest to the partner.

Based on experience in nearby wells and Eagle Ford proven production in three directions from the acreage, the company said, it anticipated an initial potential for 8 MMcfge/d. At a gas price of $5.50/Mcfg, the project would pay out in 2.2 months on the initial re-entry well.

If the well produced 8 Bcfge over its life at the same price, the 72% net revenue interest would generate more than $112.7 million to the 100% working interest, WEJCO said.