While activity in US shale plays escalates from the Marcellus to the Monterey, unconventional resource experts, industry players, and shale play hopefuls gathered in Fort Worth April 18-20, 2011, at Hart Energy’s sixth annual Developing Unconventional Gas (DUG) Conference & Exhibition to examine the latest developments, issues, and challenges.

First-day speakers described the current role of shale gas as a US energy resource, citing more than once the US Department of Energy estimate of total US oil shale resources of 6 trillion barrels of oil as well as FERC’s estimate of 742 Tcf of technically recoverable shale gas resources. Presentations noted that, according to IHS Cambridge Energy Research Associates, shale gas was only 1% of the US natural gas supply in 2000; today it is 20% and could reach 50% by 2035.

With at least 22 major shale plays in the US, unconventional resources have the potential to play a significant role in meeting increasing global energy demands. More than 2,400 DUG participants came to the conference with questions about shale gas operations, financial opportunities, and environmental and regulatory issues. They were privy to beyond-the-Powerpoint information on company strategies, activities, and more during intimate Q&A sessions following the presentations. Recurring talk-points included collaboration on technology and industry-wide recognition of the importance of educating the public and respecting community concerns to minimize public relations crises when incidents occur. Following is a sampling of wide-ranging comments from the leaders in today’s unconventional resources sector.

Financial opportunity

Opening keynote speaker Steven Trauber, vice chairman, global head of energy, Citigroup, noted the potential for a record number of initial public offerings this year. “In addition to the 13 IPOs we’re currently mandated on that are scheduled to come this year, there’re probably another 10 or 11 that we’re actively pitching that will likely come this year. There’s a tremendous amount of equity to be raised in the energy sector,” Trauber said.

Trauber explained that the deals include upstream, midstream, and services transactions. “Small companies who have grown because of commodity prices or because of continued development of their reserves seek capital,” he said. “The equity capital markets are very open to upstream companies today, particularly growth-oriented companies, which many of these are.”

Seismic in the shales

There is tremendous opportunity in areas such as the Western Anadarko Basin because it’s been delineated over many years of development, according to George Solich, president and CEO, Cordillera Energy Partners. Responding to a question about whether the company’s vertical well database adequately prepares the operator for subsurface mapping, Solich said, “We strongly believe that the vertical well control is what allows us to develop this play horizontally. As our manager of geology tells me, seismic will do nothing more than help us stay away from geohazards. We feel pretty confident that based upon the drilling we’ve already done and based upon the drilling the industry has done, we can stay away from those geohazards. We're not driven technically by geophysics.

“I think plays like the Niobrara are going to be 3-D driven because the fracture identification is pretty critical,” he said. “It really is play-specific, and some companies, no matter where they are, are going to shoot big regional 3-Ds. Other companies may be a little bit more selective.”

Solich encouraged attendees to consider “how we got here.” “You know what development happened originally and what we were looking for,” he said. “What we look for today doesn’t look very great on the logs. We wouldn’t look at those logs twice 20 years ago. It’s the intersection of horizontal drilling and fracture stimulation -- there is so much potential in areas where you have delineated the resource.”

Now that operators are “looking at much more,” Solich voiced the question on many delegates’ minds: “How do we capture the resource as efficiently as we possibly can?”

Drilling and completions

At the root of the explosive development of unconventional resources are the advancements in horizontal drilling and hydraulic fracturing, which have dramatically improved the industry’s ability to economically recover natural gas from shale rock. DUG attendees asked a variety of play-specific questions during the Q&A sessions.

President and COO Richard Stoneburner highlighted Petrohawk Energy Co.’s activities in the Eagle Ford and Haynesville shales.

On well spacing in the Eagle Ford: “It's really too early to answer,” said Richard Stoneburner, president and COO of Petrohawk Energy Corp. “We're going to have a tighter spacing in the Eagle Ford than we are in the Haynesville because the gas-in-place numbers are equal to or greater than the Haynesville, but the recoveries per well are not nearly as high. We do have one section that's fully developed. We can't really project a whole lot from that. It's got seven wells on it, which would be about 90-acre spacing. That feels about right to the engineers, and we've got a bunch of models that suggest that that might be about right.”

Asked when the Bossier might come online, Stoneburner said, "The Bossier is way down the road. I can only speak to what we have planned: around 2013, we're going to drill probably one out of five wells in the Bossier. We'll pick a section to develop and have one rig that might be devoted to a Bossier development. The other four rigs will be developed to Haynesville on a pro rata basis. I think we have a total of 50 wells we have an interest in, so it's way too early to know too much about the Bossier; we want to learn about it.”

When will the balance shift from holding leases to decisions based on profitability? Said Stoneburner, “We don't complete lease capture in its total in the Haynesville until about mid-2012, but it's a very nominal amount relative to what we've been spending. When we get to about the same time in 2012, Black Hawk is totally discretionary.

“Discretion in Black Hawk means you ought to drill as much as you can. Then you have Hawkville. It has leases held, but a continuous development clause is kicking in all across the board, and these large leases have very significant continuous development clauses.

“So the long answer is, the discretionary component really kicks in in that second half of '12, but the asterisk is that you don’t want to abandon the Haynesville. You want to keep drilling Haynesville wells; they're still very commercial, and they're still good. We just won't drill them at the same pace. Instead of 17 rigs, it'll be eight or 10 rigs.

“And then we've got to commit X number of dollars to Hawkville based on the continuous development clause. The rest of the pot will go to Black Hawk, the leader of the pack. So that's how we'll do it, and it will start in the second half of '12.

“I don't want to comment on '12 because you craft your budget based upon commodity prices. We have to look at what is in front of us in '12 and what our obligations are with our continuous development at Hawkville, our desire to have a minimum rig case in the Haynesville, and then what's left. If there's a whole lot left, it's all going to Black Hawk, period, end of story.

Shale economics

According to Stoneburner, real efficiencies from drilling and completion technology in the Haynesville are going to gear toward full section development. “We haven't been able to deploy the technology of batch drilling,” he said. “The idea is that you drill a well to casing point with that fluid, drill the next well to casing point with that fluid, then wait and switch those fluids out.”

Stoneburner explained the time element involved in switching out fluids from water-based to oil-based muds and said that when that can be done over a set of wells, cost-savings can result. This is one of several line items that the company’s strategic planning group has identified; others include location costs, land and legal work, and facilities sharing, Stoneburner said.

“We think that the component of efficiencies is greater than a million on savings, maybe as much as a million-and-a-half per well,” he said.

Providing a broader perspective of the company’s plans, Stoneburner outlined Petrohawk’s production strategy. “For 2011, we expect liquids to comprise about 12% of our volume on an equivalent basis and about 27% by revenue. In just a short period of time, we'll have 27% of our revenue driven by liquids

“Next year it looks like we'll probably be between 40% and 50% revenue by liquid and about 20% to 25% by volume. We'll have gone from 98% gas to around 75% gas by 2012, and that will continue to trend down. I hate to get much beyond that point for a prognostication because it depends on commodity prices. But if the forward curve is right, then I would suspect we would continue that shift from gas to liquids in 2013.”

Industry veteran James Henry, CEO of Henry Resources, told attendees in the Q&A session that he believes technology versus commodity prices is the driver behind shale economics, specifically on the east side of the Wolfberry.

“We started in 2003 when the oil price was US $30/bbl,” he said. “But the problem was at that time, the drilling and completion costs were about $800,000. It’s about 50% more now. But the oil prices increased. We’re also doing more frac stages and higher volume. So that’s increased the cost.

“But that’s been mitigated somewhat by the fact that now we drill them in 11 days; when we started out, we were drilling them in 17 days. PDC bits have made the difference.”

According to Henry, the threshold price for drilling economically is $70. “But it’s a very blurred line,” he said. “It could go down to $60 or $50. And it could go up to $80 or $90.”

He added, “When it gets uneconomical, service prices have got to come down and a lot of other things come down. So it makes it more economical at lower prices.”

Jay Ottoson, executive vice president and COO, SM Energy, which does about two-thirds of its activity in the Bakken, said it’s a great play and “at $100 oil it works fine with costs where they are.”

He added, however, that the company is somewhat conservative in its Bakken view. “We've been fairly cautious about our Bakken program, partly because we've been pretty stretched on CAPEX given all our Eagle Ford activity.” He noted the current cost of inflation in the play and that vendors are asking for long-term commitments.

“I think what you're going to see is that returns in the Bakken are going to get pinched over time,” he said. “You’d better be in a great spot, and you’d better manage costs. For the next few months, as these guys who have made these big acquisitions start ramping up rig count, I think service costs are going to keep going up. So it's not a great time to be making a lot of long-term commitments in the Bakken.”

Ottoson shared his company’s philosophy with attendees, saying, “You have to be disciplined in this game. If you don't have a strong geologic concept, you should not be buying. As a small company, we have a process to make sure that we have a strong concept before we start buying acreage.”

He noted the challenges involved in cost-effectively testing acreage. “It gets down to how much it costs to know for sure that the play is going to work or not work. You can spend a lot of money getting to that point and managing that process.”

Regulatory, environmental and social concerns

Olivier Lazare, vice president, new business development, Shell Exploration and Production Americas, was asked about the differences in operating in South Texas versus Pennsylvania.

“Permitting for infrastructure, particularly pipeline, is actually slower than what had been portrayed to us when we looked at the opportunity,” Lazare said. “It's not a matter of weeks; it's actually months.”

But Lazare put a greater emphasis on the problems surrounding local issues. “Each location has its own challenges,” he said. “It’s one thing to get permits but another to get local society acceptance because most of the time that's where issues come up.”

He noted that in the Internet age, each individual has immense power, which can be troublesome if people have wrong or misleading information. If that information gets into the papers, it can create a big issue, Lazare said.

Olivier Lazare, vice president, new business development, Shell Exploration and Production, described his company’s success in the Marcellus and Eagle Ford plays at DUG 2011. (All photos courtesy of Alexander’s Fine Portrait Design, © Alexander Rogers 2011)

Engaging people by informing them of potential disturbances such as truck traffic and then trying to reduce or eliminate it is one example of a mitigation measure, Lazare said. “It's so important to be really, really good at this game. We also need to be very good in terms of our operational capabilities. You can't have blowouts in neighborhoods and not expect issues.”

Lazare pointed out that the industry needs to do more to be transparent and establish its credibility before issues occur. He commended the industry on its good work in terms of advocacy. “There are initiatives like the disclosure on the hydraulic fracing fluids that make a lot of sense. You're not going to win an argument by saying trust me, these things are not hazardous. You have to step ahead of that and be more forthcoming.

“You will not win some battles, but you can win the war by being very consistent, up front, and willing to engage,” he said.

Ottoson shared his concerns about the current political environment. “We're optimistic about the future of gas in this country,” he said, “but I'm convinced there are a lot of people out there who are fundamentally against the use of hydrocarbons, regardless of how clean you pitch gas.

“There are a lot of people in our world who honestly believe that what we do is ruining the environment, and it's not just our fracing, it's not our operations, it's the product we produce,” Ottoson said.

He foresees a long uphill battle in convincing people that gas in particular is a great fuel with significant environmental benefits. “We're all going to have to work together as an industry to make sure that happens. I'm very optimistic about the resource potential in this country, but at times it can be pretty discouraging,” Ottoson added.

Moving forward

Lee K. Boothby, chairman, president, and CEO of Newfield Exploration Co., is also excited about “what’s going on in the wet gas condensate and oil plays today.” He, too, recommends sharing ideas whenever possible. “There are a lot more resources underfoot than any of us realized just a few years ago. I think that the industry’s got the talent in both the upstream and downstream sides to solve this puzzle. There’s a lot more to be learned and done, and we’ll get there quicker if we work together,” he said.

Following his luncheon keynote address at the Developing Unconventional Gas Conference & Exhibition in Fort Worth in April, Bush sat down with Oil and Gas Investor's Editor-in-Chief Leslie Haines to share his thoughts on energy, being Commander-in-Chief, and his advice for E&P professionals.

Henry reviewed the tremendous learning curve rising from the 1950s to present. “In the 1950s we drilled down through the shale,” he said. “In the 1980s we drilled on 2-D seismic and got 20% recovery. And then in the 1990s, we drilled 3-D seismic and got 80% recovery.”

Henry noted the industry didn’t stop learning as it started doing frac jobs. “In the frac jobs themselves and the geology and formations, there’s a learning curve. We’re still learning.”

There are many formations that are uneconomical now that will be economical in the future, Henry pointed out. “Where you have an economic incentive, give these oil people a try and they’ll find a way to do it,” he said.

In separate comments, Boothby concurred with that optimistic view. “The neat thing to me in watching the industry is that it’s still exploring for opportunities,” he said. “It still comes down to individuals and specific companies being willing to take a chance.”