Residents of South Texas are not unacquainted with the oil and gas industry; oilmen have been poking around the scrubby landscape for decades. It's just that in the past year or so, things have gotten a little crazy—even feverish, you could say. And it's all over an unseen and previously unappreciated resource lying dormant a mile or two below those mesquite trees: the Eagle Ford shale.

This dense rock formation, stretching from the Mexico border and northeast a couple of hundred miles, is rich in natural gas, gas liquids and oil. But it is the liquids portion of the hydrocarbons fanning the frenzy. These commodities command a premium at sales, while gas prices lag.

Sparsely populated by working-class folks of modest means, rural South Texas is suddenly being flooded with billions of dollars in capital investments and a tidal wave of workers putting that capital to work.

Drilling rigs in the region have doubled to 150 since the end of 2009, according to RigData, with Eagle Ford-targeted rigs tripling. Housing is unavailable across several counties. Small-town cafes are brimming with oilfield workers.

"This is the play," asserts Bob Thomas, a partner with Porter Hedges LLP and head of its energy practice group.

The allure is great for these elusive liquids. Independent producers are jockeying for position for every available acre, and major integrated and international energy giants from Europe to China are staking claims, confirming the Eagle Ford as a world-class resource.

"This is the play," asserts Bob Thomas, a partner with Houston law firm Porter Hedges LLP and head of its energy practice group. Thomas has advised on several Eagle Ford transactions. "Demand is high. Wells have performed up to predictions. Economics are better. This is one of the best resource plays in the U.S. right now and companies feel it is important to be in it."

New kids on the block

With soft gas prices forecast for the next several years, independent producers are retooling portfolios toward oil and gas liquids, with the Eagle Ford clearly in their sights. Since 2008, more than 5 million acres have been leased, and almost all—more than 90%—in liquids-rich areas, according to DrillingInfo statistics.

"That's why you have rigs coming from the Haynesville shale down to the Eagle Ford," says Chris Simon, managing director and head of asset A&D at Houston-based investment bank Raymond James & Associates. "The attractive rates of return are in the liquids-rich drilling opportunities. That's where companies are investing their capital."

Says Chris Simon, managing director and head of asset A&D at Raymond James & Associates, "Never before have I seen as many transactions on the market in one play at one time."

Although the Eagle Ford region features a proven prolific window for natural gas, the quest for liquids-rich assets is fueling M&A activity and valuations in South Texas. And 2010 was a breakout year, with 18 major publicly announced transactions totaling $8.2 billion.

"It was a tremendous year," says Simon. "Never before have I seen as many transactions on the market in one play at one time."

Jason Simmons, a research analyst with DrillingInfo Energy Strategy Partners in Austin, Texas, agrees. "The main driver is oil price—it comes down to economics."

Robust economics combined with scale have garnered the attention of international majors, a new breed of buyers with significant cash coffers that now call South Texas home: The Netherland's Royal Dutch Shell, Norway's Statoil ASA, Britain's BP Plc, India's Reliance Industries Ltd., Canada's Talisman Energy Inc., and China's CNOOC Ltd.

"Major international companies want to be in the Eagle Ford," says Ward Polzin, managing director and head of A&D for energy advisory firm Tudor, Pickering, Holt & Co, which represented CNOOC. "It's got liquids, it's got scale, and it's got infrastructure for big field development that they can build on."

Talisman and Statoil are good examples of international companies moving in, notes Porter Hedges' Thomas, who advised Talisman in two deals. Calgary-based Talisman has sold upward of $5 billion of conventional assets in Canada with plans to redeploy a substantial portion of those funds into U.S. resource plays, including the Marcellus and Eagle Ford shales. In early 2010, it bought some 37,000 acres in LaSalle and McMullen counties from Common Resources LLC.

"Major international companies want to be in the Eagle Ford," says Ward Polzin, managing director and head of A&D for Tudor, Pickering, Holt & Co.

Later, Talisman joined Norwegian national oil company Statoil, which also holds a sizeable nonoperated position in the Marcellus. Together they acquired another 97,000 acres in the liquids-rich window of the Eagle Ford from Denver's Enduring Resources LLC.

"These two international companies are coming to play and deploy money," Thomas says.

Both companies bought the interests outright and will operate. Others, like CNOOC and Reliance, prefer the formalized nonoperated structure of a joint venture, and are willing to pay a premium, says Polzin, although Reliance is now negotiating future operating rights in its bids. Shell, on the other hand, already held a historic position here, and only bolstered that with its $1-billion minerals purchase of the Harrison Ranch.

"The international companies are going to pay more per acre than public independents," he says—about 10% more.

Financial investors are active as well. Private-equity giant KKR joined with Hilcorp Energy Co. in a $400-million venture to develop Hilcorp's Eagle Ford acreage, and subsequently, KKR and Hilcorp committed an additional $125 million to purchase additional Eagle Ford interests from privately held Texas Crude Energy Inc. Thomas, who represented both Texas Crude and Hilcorp, says many private-equity-backed E&Ps are actively bidding on Eagle Ford assets.

Condensate envy

The Eagle Ford shale is comprised of three geologic zones, or "windows." South of a diagonal line following the Edwards shelf margin, dry gas is predominant. Oil is prevalent north of that trend, and a rich mix of gas and condensate populates the meeting of the two. Valuation metrics, though, vary by window and proximity to production.

The majority of Eagle Ford deals since second-half 2009—$4.6 billion worth—targeted the condensate window, the thin transitional band between the oil and gas regions. Here, economics are the strongest and the most production data points exist. Valuations in the condensate window have ratcheted up to $10,000 to $12,000 per acre, from $3,000 at year-end 2009.

The joint venture between Reliance and Pioneer Natural Resources in June, encompassing a 95,000-acre swath from McMullen and up through DeWitt counties, set the top mark in the overall play. "The economics are best in the condensate window," says Polzin, who advised Reliance in the deal. "If it's got the best economics, it should get the best price."

Says Simon, "The condensate window has relatively higher rates of return than the oil window, due to the relatively higher initial production rate, the high Btu nature of the gas, which allows it to be processed into NGLs, as well as the condensate produced at the wellhead. Both NGLs and condensate are tied to crude prices, which are strong. That being said, the oil-window returns are very attractive as well."

Market activity reflects that boost. "There are a number of assets located in the condensate window that are on the market now, and they're getting done."

"Any deal or leasing we've seen recently is all happening near the gas-condensate or oil window," confirms DrillingInfo research analyst Jason Simmons.

"Any deal or leasing we've seen recently is all happening near the gas-condensate or oil window," confirms DrillingInfo's Simmons. "The permitting is happening in that area, too."

According to Simon, the biggest factors determining valuations are twofold: the proximity of properties to existing production and therefore proved reserves, and well performance. "It's a big area and different areas have different levels of maturity."

For instance, the condensate region around Hawkville Field, spread across LaSalle and McMullen counties, has more performance history than many other areas, and is experiencing the most transactions and some of the highest valuations. "That's one of the core areas of the play," says Simon.

"New entrants to the play are studying the data very hard. They're anxious to see performance history to build up their confidence on these newer wells. Transactions that have some production history have realized the most attractive valuations."

Still, those values have likely reached a plateau, suggests Polzin. "I don't expect them to go down, but I also don't see them taking a step up, because they're reflective of oil and gas prices." But, he says, "if oil goes to $120, I take that back."

Competitive returns

With a worldwide portfolio of exotic opportunities, Anadarko Petroleum Corp. views its approximately 300,000 net acres on the far western edge of South Texas and solidly in the condensate window of the Eagle Ford as a strategic growth asset. Its onshore U.S. strategy includes a strong liquids focus, and the 450 million barrels equivalent of resource potential in the Eagle Ford is a primary target.

To date Anadarko has drilled some 100 wells with more than 2,000 additional locations anticipated. Estimated ultimate recoveries exceed 400,000 barrels of oil equivalent (BOE) per well with average drilling costs hovering around $5 million. And with upward of 80% of total value from liquids, the economics top an enviable 65% rate of return.

"We're excited about it," says Doug Lawler, vice president of operations, Southern and Appalachian region, for Anadarko. "We consider the liquids-rich nature of the production to be extremely valuable. It offers competitive returns in our portfolio to be able to compete for capital funding."

Consistent with the company's philosophy of entering a play early and developing it organically, The Woodlands, Texas-based Anadarko began building its position as early as 2005. Its leasehold activity targeted both the Eagle Ford and deeper Pearsall formations in southern Dimmit and Maverick counties and in northern Webb County, with an average entry cost of less than $600 per acre.

TXCO Resources Inc. and SM Energy Co. each subsequently took a 25% promoted position, with Anadarko reclaiming TXCO's interest in early 2010 through a bankruptcy sale for roughly $1,100 per acre, the lowest acquisition metric recorded in the play.

While Anadarko will consider such bolt-on opportunities, its position is essentially set. "Once prices begin to escalate, it significantly reduces the economic return to the project," says Lawler. "We believe the greatest value is created from a low-cost organic entry. We would rather put the money into drilling as opposed to leasing acquisitions."

Lawler says the company was attracted to the western edge of the play due to the shallower depth and stacked pay. "With the shallow depth comes a lower cost of development drilling vs. some of the deeper Eagle Ford further east and north," he says. "We believe we have superior value in the play compared to our competitors.

"Not only are we one of the largest producers, but we also believe we're generating the greatest value because of the revenue associated with the liquids-rich production. When you look at the actual cost to drill and complete, we're one of the lowest-cost and one of the most capital-efficient companies in the play."

Typical vertical depth here averages 8,000 feet with a pay thickness of 300 to 500 feet. At present the company is drilling 5,000- to 6,000-foot laterals into the lower portion of the zone with 15 to 18 fracture stages per well using a hybrid slickwater and gel recipe. This combination has resulted in initial production rates of 500 to 800 BOE per day on average, with some wells producing more than 1,000 BOE per day.

"The liquids-rich nature of the condensate and natural gas liquids offers excellent economics. It's very competitive in our portfolio."

So much so that Anadarko has moved four rigs out of the East Texas and Haynesville shale operations—decidedly dry-gas plays. "We've moved rigs to the Maverick Basin because of the superior economics," Lawler says.

By the end of the first quarter, Eagle Ford activity will jump to 10 rigs from six at year-end and only two at the beginning of 2010. With a cycle time of 10 to 12 days, Anadarko plans to drill about 200 wells this year. And with 70% of drilling operations targeting full development over lease commitments, three-well pads are becoming the norm. Current gross production is approximately 25,000 BOE per day.

With upwards of 80% of its total Eagle Ford value from liquids, Anadrako's economics there top an enviable 65% rate rate of return. "We're excited about it," says Doug Lawler, vice president of operations, Southern and Appalachian region. More than $8 billion in Eagle Ford shale assets traded hands in 2010.

Lawler says the company has carefully measured the accelerated activity against availability of stimulation crews and take-away capacity. Its operating efficiency is better than 90%. "We manage our inventory such that we don't lose value by building an excessive number of wells requiring completion. For 2011, we have all the resources and infrastructure secured to execute that program."

The Pearsall shale, prevalent across Anadarko's holdings, remains an upside option when gas prices return to happier levels. Though the company is drilling evaluation wells into the Pearsall, "it just can't offer competitive economics in our portfolio, being dry gas. But it provides great option value for Anadarko in the overall development of the Maverick Basin."

Anadarko is one of the few remaining companies holding a large Eagle Ford position that has yet to sell or partner through a joint venture. At press time it continued to coyly offer a portion of its position to suitors, but not needing the cash to drill that other companies, both large and small, require, it remained laissez-faire in its commitment to getting a deal done.

"We have high expectations and believe that our development efficiencies are going to add a lot of value," Lawler says. "If we're not able to secure the price and value that we perceive it is worth, we won't enter a joint venture."

Would a deal accelerate operations? "We potentially could increase activity, but we want to maintain the best capital efficiency without building up a large backlog of wells to be completed. We're paying close attention to optimizing the greatest value."

Betting the oil side

While most Eagle Ford activity from leasing to drilling to selling has centered on condensate-rich acreage, the oil zone above it holds ample opportunity—as well as question marks. By second-half 2010, buyers began trending northward into the oilier regions, with eight deals completed over the course of the year totaling $3.4 billion and 770,000 net acres. By year-end, oil-window valuations trailed condensate only slightly at $8,000 to $10,000 per acre. That compares with no deals prior to 2010.

"We expect to see higher valuations in the oil window as more wells come online and we continue to see positive results," Simon says. "It's already playing out as we've seen a healthy increase in the oil-window numbers in the latter part of 2010."

Plains Exploration & Production Co. paved the way with a $578-million deal with Dan A. Hughes Co., a private company in Beeville, Texas, to purchase 60,000 acres in Karnes County. It paid $9,600 per acre for an asset deal that was first marketed as a joint venture. The acquisition is in alignment with Plains' strategy to sell down its Gulf of Mexico position and redistribute funds into onshore oil assets.

Says Chris Smith, research analyst with DrillingInfo Energy Strategy Partners, "There are not many data points in the oil window , so it's hard to go out on a limb and say anything really great about the oil window."

CNOOC quickly followed into the oil window, taking a one-third interest in Chesapeake Energy Corp.'s 600,000 broad footprint across Webb, Dimmitt, LaSalle, Frio and McMullen counties. Considering half of the $2-billion price tag is for drilling carries, the $10,800 per acre remains the highest valuation for Eagle Ford oil.

But while hope floats for Eagle Ford oil economics, much remains unknown. Chris Smith, a research analyst with DrillingInfo Energy Strategy Partners, holds out caution.

"There are not many data points in the oil window, so it's hard to go out on a limb and say anything really great about the oil window," he says. Unlike the prolific carbonate-hybrid Bakken shale in North Dakota, the Eagle Ford is a true shale, and "shale-oil production has not really been done yet. We don't know what the decline curves are going to be."

Industry activity in the oil window, including aggressive permitting and capital commitments, looks promising, however. "It's a good sign, but I'd like to see these wells come on for six to nine months before I get a good feeling about them. We're in a wait-and-see mode to identify what are the real economics in the oil window."

Goodrich's new life

Goodrich Petroleum Co. saw the writing on the futures wall in mid-2009. Levered 98% to natural gas (including an enviable position in the Haynesville shale), the company determined it needed diversification in its portfolio—and fast.

"We couldn't just rely on drilling gas wells, our hedges and playing defense while waiting for gas prices to turn," says Rob Turnham, Goodrich president and chief operating officer. "We needed to be proactive and find something that would work in the oil plays. Those returns were far superior to what we were seeing on the gas side."

The Houston-based producer didn't have the cash to play hardball in a material way in the established liquids-rich plays like the Bakken shale or Permian Basin, and the Granite Wash was too small geographically to get a significant presence by the company's analysis. Goodrich zeroed in on the Eagle Ford for its liquids infusion. "It looked prospective and had a lot of running room."

Rob Turnham, Goodrich president and chief operating officer, say, "We couldn't just rely on drilling gas wells, our hedges and playing defense while waiting for gas prices to turn."

The company made its entry in May with a cash-and-carry deal with San Antonio private company Blackbrush Oil & Gas. For $10 million down and a $44-million drilling carry, Goodrich could earn up to 80%, or 30,000 net acres situated in the oil window in LaSalle and Frio counties, gaining a foothold and prospects, with little capital expended.

Goodrich subsequently acquired an additional 10,000 acres, boosting its holdings to 40,000 net acres. The average purchase price equates to $1,650 per net acre.

"It's a huge shift for us and potentially a game-changer," Turnham says. "To have the ability to shift dollars between plays and send it to where you're getting the better rates of return will be an option we've never had."

A week after the Blackbrush closing, EOG Resources essentially launched the Eagle Ford oil play with its analyst-day announcement. Prices skyrocketed. And Goodrich's acreage abuts Chesapeake's, the highest-valued land in the oil play.

"We got in at the right time at the right price and were able to get a strong foothold. If you look at the potential impact 40,000 net acres has on a company of our size, it is tremendous leverage to the commodity if the play works as we expect."

This one strategic move gives the company new life. With liquids volumes jumping from 2% before the deal to an estimated 15% by year-end, Goodrich anticipates being cash-flow neutral entering 2012.

"We feel like the funding gap between capex and cash flow shrinks to a very manageable number. It's a great benefit that we have that flexibility."

Goodrich drilled its first three Eagle Ford wells in fourth-quarter 2010. The first in Frio County produced 667 BOE on a 24-hour rate from a 4,400-foot lateral. The second produced 1,010 BOE per day with a 5,900-foot lateral. The third is pending completion.

Leasing activity concentrated in liquids-rich areas increased significantly in 2010, led by LaSalle, Dimmit, Webb and Atascosa Counties.

Turnham says the company is targeting 6,000-foot laterals with 20 frac stages for other wells, and could push them to 8,000 feet in time. "They're doing that in the Bakken and it works well."

With well costs anticipated to be around $7 million and estimated ultimate recoveries (EURs) of 465,000 BOE based on offset data, "we're looking at a 45% rate of return. It's a potential huge impact."

Goodrich is "cautiously optimistic" in its secondary target, the Buda lime just below the Eagle Ford trend with a two-thirds oil-to-gas mix. With natural fracturing, these wells require no stimulation and are thus cheaper to drill—about $3.5 million per well. Turnham estimates an average EUR for these wells at about 200,000 barrels equivalent, making them even more economic than the Eagle Ford. But the Buda is less consistent than the Eagle Ford and carries more performance and geologic risk.

Goodrich ran one rig targeting both the Eagle Ford and Buda in 2010 and exited the year with two, the additional rig pulled from its Haynesville shale program. In 2011, one rig will home in on Eagle Ford solely, while the other will split time with the Buda.

In all, the company is swing-shifting almost 50% of its capital budget to the Eagle Ford oil window, or $100 million. Turnham expects to drill 20 wells in the play this year, exiting year-end with approximate production of 3,000 barrels per day.

But don't expect Goodrich to get all wet behind the bit: gas still allures.

"We'll always have oil in our mix going forward, but we're not going to abandon gas. At this point in time we're shifting a lot of dollars to the oil play because of the rates of return down there. But expect gas to rebound at some point, and you'll see us continue to throw capital at the gas plays as well."

For now, with 500 net locations in South Texas and oil prices hovering around $90, "we've got a long way to go. It's going to keep us busy for years to come. We're very excited at the potential."

Gas rocks

Although the dry-gas window kicked off the play with bravado in 2008, moribund natural gas prices have stifled activity since. Just one significant dry-gas deal has been logged in the past year: BP's partnership with San Antonio's Lewis Energy Group. Although deal terms are undisclosed, Raymond James' analysts estimate the value of the deal at approximately $4,000 per acre.

"Until we get more strength in natural gas prices, we're not going to see as much activity there," states Raymond James' Simon.

At least not in the deal category, but operators are still drilling away at the dry gas to hold acreage. According to DrillingInfo, 190 permits were issued in the dry-gas region in LaSalle and Webb counties last year, with 62 known to be targeting the Eagle Ford. "Operators talk about how nice these wells are but that the economics just don't work," says DI's Smith. "But they don't want to let those positions go."

One such operator, and unabashedly so, is Lewis Energy Group founder Rod Lewis. "We're gas players," says Lewis. "We want gas and we like gas—even the dry gas."

The privately-held Lewis Energy has been seeking South Texas gas for 30 years. It currently holds some 460,000 acres concentrated in LaSalle and Dimmitt counties, all prospective for the Eagle Ford shale. Of that, 60% is lean gas, 30% rich condensate, with 10% oil. And Lewis doesn't much care for the oil.

"I don't think it's proven yet. There are experts in the oil; let them play it. I like the condensate and the dry gas—and that's all I'm going to play."

Even before Petrohawk Energy Corp. publicized its serendipitous dry-gas find in 2008 that instigated a run on the play, Lewis Energy had already been drilling successful Eagle Ford wells for five years.

"I give all the credit to Petrohawk for coming up with the proper frac technology, but they didn't discover the Eagle Ford," Lewis says. "We drilled a lot of horizontal wells in the middle 2000s that no one knew about. We and EOG (Resources) were pushing this formation way before these other guys even thought about it."

Lewis currently runs nine rigs piercing the Eagle Ford, with lateral lengths averaging 5,000 to 7,000 feet. To date, Lewis has drilled 47 Eagle Ford wells.

The company also holds an additional 80,000 acres in the Mexican Eagle Ford play across the border, the only non-Mexican operator allowed in the play and the first to drill a horizontal well in Mexico. But that's another story.

Economic returns for condensate wells run as high as 60%, Lewis says, but cautions that figure drops below 20% if costs run high. "I'm not much for the herd mentality, but right now I like the returns in the rich," he says. Returns are "slim" on dry-gas wells, he acknowledges, around 18% "if you can drill them cheap with no problems. We're able to make money on dry gas because our costs are low."

Not that he wants to drill dry gas now. Gas drillers are their own worst enemies by continuing to add gas to the market, his company included, he concedes. "If we had enough sense, we'd park the rigs for awhile. We know there's an abundance of gas and that the market is flooded with these kinds of wells."

Says lewis Energy Group founder Rod Lewis, "There are experts in the oil; let them play it. I like the condensate and the dry gas-and that's all I'm going to play."

But Lewis blames landowner attorneys and royalty owners for pushing to drill and to get wells online in a low-price environment. "We've got our backs to the wall." Some 80% of Lewis Energy's program is directed to leasehold commitments. "That's what's fueling this catastrophic price," he says. "We operate out of cash flow. We don't have the wherewithal to drill a hundred wells and just let them sit."

Soon after Petrohawk's announcement of its 9-million-cubic-foot-equivalent (Mcfe) per-day well in October 2008, landmen scouring the region quickly discovered Lewis Energy had much of the land sewn up. "Within 90 days every major company had approached us to buy our position," Lewis remembers. "They found out quickly we weren't going to sell, so they attempted to partner."

BP came to the top because of its geological and geophysical (G&G) expertise. "They have the best science out there. We think we made a good decision going with BP over the other players now in the play."

While he won't disclose the terms of the deal, Lewis confirms the reported $200 million cash-up-front paid for a 50% position in 80,000 acres is too low. The partnership now holds a combined 160,000 acres and Lewis has been assigned all field operations as of the first of the year, a role previously divided.

Why join with a major? "Capital, number one. We were able to get an injection of capital that allowed us to staff up and buy additional equipment." The G&G advantage was another reason.

Lewis owns its own rigs partially because it operates in remote areas and also to shield it from boom times like now. "We would be taken to the cleaners because service companies can name their price. If you're not a low-cost operator in the Eagle Ford, you're just not going to make it."

In fact, four new 1,500-horsepower rigs custom-built for the Eagle Ford are being delivered by the end of February. "Nobody has a rig like we're building," he says. "We expect to rig up and spud within 36 hours. Some of these big rigs are five to seven days for rig up and rig down." Lewis Energy's current well turnaround is 15 to 20 days.

Likewise, the company recently acquired its own frac equipment, and is currently pumping 50% of its own hydraulic fractures. It hopes to manage all stimulations internally within nine months.

Some 1.2 million acres were monetized in Eagle Ford transactions last year.

Interestingly, Lewis claims the Eagle Ford is not the most important horizon his company is currently drilling on the South Texas acreage. Although he won't name the formation, he says, "We've taken this same technology and applied it to other zones we've been drilling for years, and it's working economically better than the Eagle Ford. We can drill this shallower zone much quicker and cheaper."

Three rigs are dedicated to this program, with 55 wells drilled to date.

Lewis Energy will spend about $450 million this year in South Texas. Current production is 180 MMcfe per day. That should increase to 260 MMcfe by the end of the first quarter when 32 wells waiting on completion come online.

For a while acreage prices "went off the charts," peaking in April 2010, but are now heading back down, says Lewis. He believes patience will be rewarded with payoff as prime acreage resurfaces.

"We're waiting for these guys that jumped in and paid all this big money. A lot of them stepped out and now can't handle the drilling obligations, so we're seeing a lot of opportunities to pick up acreage. We're just sitting on the sidelines." Though not entirely, as he acknowledges "significant" leasing additions in recent days.

When gas is near or below $4, "most of these companies aren't going to make it. Their well costs are too high. This is a $6 play, after all, and we're bullish long-term on gas. We plan to gobble up some of these guys."

The next wave

If Anadarko consummates its lofty partnership, it will likely be the finale in a string of large joint ventures in the Eagle Ford as it is the last large package on the market in the play. "Most of the big deals are done," says Tudor Pickering's Polzin. "Almost all of the big positions have been joint ventured into."

The only other unwed operator with a sizeable position—some 500,000 acres in the oil window—is EOG Resources Inc., which has stated selling down to a partner is a last option. Instead, it is divesting a host of conventional gas assets to raise in excess of $2 billion to have the capital to independently develop its unconventional-oil holdings.

The end of available big positions thus foretells an end to marquee names too, but an opportunity for joint ventures with smaller international companies may be rising. For an average deal size of $50- to $500 million, "we could see a hotbed of activity in that range," says Polzin.

While he believes the billion-dollar packages have played through, he sees a robust market in what he terms Tier 2 packages. "There's definitely strong deal flow with a strong mix of higher and medium-risk opportunities" around the edges of the play.

Raymond James identifies about 476,000 net acres that are currently being marketed, most in the oil and condensate windows.

Porter Hedges energy lawyer Bob Thomas expects international companies already in the play will try to continue growing through further consolidation. "I expect them to expand their presence. It wouldn't be a big move on their part. With so many small independent players that have leased up so much of this land, that's a pretty good buyer/seller match. They'll continue to pick up pieces."

Polzin expects Eagle Ford deal flow to remain strong throughout this year, but predicts overall deal value will drop in tandem with anticipated shrinking deal size.

"In terms of volume, 2011 will be as good as 2010," he says. "As long as oil prices are high, it will drive companies to oil and liquids deals, and the Eagle Ford is right there."