Some 4,000 Eagle Ford shale aficionados gathered in San Antonio, Texas, in October for Hart Energy’s Developing Unconventional Gas–Eagle Ford conference to talk about one of the world’s most desired shale-gas plays. But notably, three operators took the stage to talk about other hydrocarbon zones in South Texas—because the economics are better than the Eagle Ford.

Better than the dry-gas window, at least, where these operators hold the majority of their interests south of the more-favored rich-gas/condensate and oil zones of the Eagle Ford shale. With natural gas prices remaining depressed, producers have focused their attention and public hype on Eagle Ford zones with liquids, which deliver higher rates of return.

Bruce Vincent, president of Swift Energy and former IPAA chairman, is enthused about results in the Olmos formation.

And yet none of these dry-zone operators seem to lament what might have been. In fact, the leaders of Swift Energy, Laredo Energy and Escondido Resources II are stoked about the potential value of the resources underlying their positions, even declaring that the economics are as good as Eagle Ford sweet spots.

Bruce Vincent, president of Swift and former chairman of the Independent Petroleum Association of America (IPAA), is high on the Olmos formation, a low-permeability sandstone that lies above the Eagle Ford. The Houston-based company currently holds about 44,000 net acres prospective for the Olmos.

“We drilled a horizontal well in the Olmos prior to drilling our first Eagle Ford well, and surprise, the economics were terrific—in a lot of ways similar to what we’re finding in the liquids-rich Eagle Ford area,” he said.

The key word is horizontal. Swift Energy has been drilling vertical wells into the Olmos here for 20 years, but it is the introduction of hydraulic-fracturing techniques combined with horizontal drilling—introduced to this scrub-brush region by Eagle Ford operators—that has made South Texas a cornucopia of revived multizone pays.

Within the Olmos trend Swift uses two economic models—one with free-flowing condensate and the other with high-Btu gas. “The gas generally runs 1,250 to 1,300 Btus, so you strip out a lot of liquids, which really improves the economics.”

The results of its Escondido wells have been “spectacular,” says Glenn Hart, Laredo Energy’s president and chief executive officer. Right, with natural gas prices depressed, South Texas producers are targeting drilling in shallower zones offering significant pay.

“We look at the Eagle Ford and the Olmos together, and we see well over 1 billion barrels of potential and multiple Tcfs of gas” on the company’s 80,000-acre Eagle Ford and 44,000-acre Olmos positions.

Swift estimates it has 275 Olmos locations on 160-acre spacing. It expects a resource potential of 6 billion cubic feet (Bcf) and costs of $8.5- to $9 million per well with a 6,000-foot lateral. That equates to a 72% and 43% rate of return for the condensate and rich-gas windows, respectively, based on strip prices. Beyond the Eagle Ford

Laredo Energy, a privately held Houston-based company with backing from EnCap Investments and Avista Capital Partners in its fourth iteration, has drilled more than 400 wells in Webb and Zapata counties over the years. Until three years ago, however, none of the team had ever drilled a horizontal well, according to Laredo president and chief executive officer Glenn Hart. “That’s all we do now.”

Laredo IV was built to focus on the Escondido formation. With previous iterations targeting the Lobo trend, in 2007 the company turned its attention to the shallower Escondido in northern Webb County. Those plans, however, were soon sidetracked.

“We didn’t go looking for a shale play, but very much to our surprise a shale play wandered into the neighborhood.”

Escondido Resources II president and chief executive Bill Deupree says the company will focus 85% of its 2012 budget on the Escondido and Olmos reservoirs.

Beating the land rush, Laredo amassed a 134,000-gross-acre (78,000 net) position prospective for the Eagle Ford 25 miles west and on strike with Petrohawk Energy Corp.’s original discovery and began proving up the perimeter. But a funny thing happened on the way to the Eagle Ford, he said.

“We were finding a tremendous amount of hydrocarbons in these wells.”

When several wells showed other pay zones, Laredo skidded the rig over and has now drilled an additional seven horizontal wells into the Escondido and Olmos formations. The results of the Escondido wells have been spectacular, Hart reported, with some showing sustained rates of 10- to 12 million cubic feet (MMcf) per day from 5,000-foot laterals.

“We’re trying not to call them 5- to 6 Bcf wells at the Escondido horizon, but some of the early results have been spectacular,” Hart said.

And how are the economics compared with the company’s Eagle Ford position? “Way better,” he said.

“Our Escondido wells are producing 1,200-plus Btu gas with liquids and condensate also,” as does the Olmos. The economics of these wells, he said, have a better profile than the company’s dry-gas Eagle Ford wells. “Factor that in and it is a tremendous delta in the price. It makes $4 gas become $5 gas.”

Laredo is now drilling Escondido wells to preserve the deeper Eagle Ford rights for when gas prices improve.

“In the short term, the economics of the shallower non-Eagle Ford wells are better.” With two rigs running, “the biggest part of our 2012 budget will be drilling non-Eagle Ford horizons. With the cheaper costs (to drill into shallower zones) and almost as big of reserves, it’s clearly the direction we should be going short term.”

Not to be ignored: other zones with significant pay, including Wilcox, San Miguel, Austin Chalk and the Pearsall shale.

Take the Austin Chalk, a dry-gas trend oft considered 1990s news. Down here in South Texas, core samples of the chalk look the same as the Eagle Ford—black rock with flecks of limestone. As Laredo drilled its first Eagle Ford wells, Hart’s geologists repeatedly insisted he look at the Austin Chalk logs.

To test the concept, Laredo took one of its early Eagle Ford horizontal wells that had declined to 1.2 MMcf per day, set a plug at the top of the lateral, and fractured two stages in the curve through the Austin Chalk zone.

“We’ve been flabbergasted at the performance of the two additional stages in the Austin Chalk,” he said. “It adds about 1.5 Bcf incrementally for a very low cost.”

The technique, he said, is one method of improving economics in the dry-gas Eagle Ford window.

Laredo followed on with two additional Chalk horizontals. “So far, it looks like the production from the Austin Chalk wells is every bit as good as the Eagle Ford.”

Combined with the Eagle Ford, the resource base of the two, including the Austin chalk, on Laredo’s acreage is huge, he said. “We’re talking 5,000 to 6,000 locations with 15 Tcf recoverable.”

For icing on the cake, Laredo put an exploratory tail on one of its vertical wells and, lo and behold, said Hart, “it looks like the Pearsall is present and productive in our area.” The company plans a horizontal exploratory well to the Pearsall in 2012 at a depth of 12,700 feet. “We’re excited about the potential of the Pearsall. Based on our experience in the Eagle Ford, it’s pretty easy to make a stab that it will be at least 5 Bcf per well.”

While the Pearsall is dry gas like the Eagle Ford here, Hart said it proves up another productive zone for long-term value, which is important to the company’s build-and-sell model. He estimates stacked-pay potential to be 18 Bcf per 80 acres where all zones are present.

hydraulic-fracturing combined with horizontal drilling has revived interest in the shallower Escondido formation, the Olmos, and others.

Hidden reserves

Bill Deupree, president and chief executive of Escondido Resources II, another EnCap portfolio company, says the Midland, Texas-based private company is at a crossroads. With 30,000 acres prospective for the Eagle Ford shale and another 60,000 in the shallow reservoirs of the Olmos and Escondido, which way should it turn its capex?

“Do we follow the pack and keep drilling Eagle Ford wells, or go a different direction and employ the new technology gained from drilling these Eagle Ford wells to our old friends the Olmos and Escondido?”

Deupree calls the Olmos and Escondido reservoirs the “hidden reserves” of South Texas. The company focused its leasing efforts on multipay opportunities in Webb, LaSalle and McMullen counties, which pushed it into the dry zone of the Eagle Ford. It now holds 60,000 acres here with a choice of targets.

The bump up in recovery and rate from horizontal drilling in the Escondido justifies the additional cost.

“The economics of the Eagle Ford in our portion of the trend are a bit diminished because of gas prices,” he said, “so we’re focusing on other reservoirs.”

This is after participating in more than a dozen wells with Petrohawk since 2008 and drilling four solo Eagle Ford wells.

Escondido Resources drilled its first Escondido horizontal well in 2009, immediately following its first Eagle Ford well, and has now drilled a total of 25 horizontal wells: 16 in the Escondido, five in the Olmos and four in the Eagle Ford.

“The Eagle Ford never replaced our efforts to develop the Escondido and Olmos,” he said. “It was an add-on to an existing successful program. The Eagle Ford did focus us on using horizontal technology in these shallow reservoirs, something that had not been done up to that point to any great extent.”

Escondido I, sold in 2007 for $250 million, drilled 190 vertical Escondido and Olmos wells with a peak production of 25 MMcf per day, “which we considered phenomenal at the time,” said Deupree. However, “Our last three wells in Escondido II will produce the same amount from the exact same reservoirs.”

In January 2011, the company drilled its best well ever, an Escondido well with a 5,000-foot lateral that had an initial production (IP) of 12 MMcf per day. Cumulative production is 5 Bcf in five months.

And the Escondido and Olmos are both rich gas, about 1,130 Btu. “We get quite an uptick from processing on those wells.”

With 15 wells completed into the Escondido, the company averaged an IP of 7 MMcf per day with 4.8 Bcf estimated ultimate recovery. It is stretching its laterals from 5,000 to 7,500 feet, anticipating 25% higher costs to drill, but an expected 50% increase in recovery and rate. The last five wells have IP’d near 9 MMcf per day, “putting us right up there with the top wells in the Eagle Ford trend.

“These results have exceeded our expectations. The economics of drilling in the Escondido and Olmos formations are excellent even in the current gas-price environment, and are comparable—if not better—than the rich-gas Eagle Ford trend.”

Escondido’s focus in 2012 will be on the Escondido and Olmos reservoirs, with about 85% of its $150- to $200-million budget directed here. All of its efforts will be horizontal.

“Overall, our results in the Eagle Ford have been good, but our results in the Escondido and Olmos have been better. We’re not going to totally exclude the Eagle Ford, but we need gas prices to improve a lot of the acreage in the dry-gas portion of the trend.”

Escondido II now sports more than 600 drilling locations across multiple objectives. Deupree estimates the company holds 2.5 Tcf or more of gross resource potential in South Texas.

“We are applying new technology to an old, established, producing area. We are now targeting these same reservoirs with horizontal drilling and large slickwater fracs, and have been having excellent results.”