BRISBANE, Australia -- Australian oil and gas producers have a standing invitation to join the 700 Club.

And, no, the 700 Club is not a subscription to a niche cable television program. Rather, the club represents the threshold number of wells needed to perfect the techniques to commercially extract hydrocarbons from tight geologic formations.

While there has been ample discussion over the years about the statistical nature of resource plays, figures on just how many wells are necessary to constitute a reliable statistical sample have been few and far between, other than vague references to “hundreds.”

But specific numbers surfaced during Hart Energy’s DUG Australia conference in August, when Aurora Oil and Gas Ltd. CEO Doug Brooks outlined trips and traps in shale play development.

“Any new resource play takes about 100 wells to prove it up and about another 700 wells in terms of how you optimize it,” Brooks told conference attendees. “Afterward, things can develop quickly.”

Aurora should know. The company holds 22,000 net acres in the Sugarkane Field, which is ground zero in the Eagle Ford shale sweet spot. Aurora got there as an early mover, partnering with a local broker to obtain leases in 2009 before the magnitude of Eagle Ford potential became generally known.

The company later brought in Hilcorp Energy Co. as a partner to drill the first dozen wells. Hilcorp brought in mega-private equity player KKR & Co. as an investor in 2010. After the smoke cleared, the Hilcorp/KKR package sold for $3.5 billion in June 2011 to Marathon Oil Corp. in a blockbuster deal that firmly established credibility for the Eagle Ford shale, which has since evolved into the world’s most active in situ oil shale play.

As operator, Marathon ramped from zero to 16 rigs in 120 days and now is drilling 300 wells annually in the Eagle Ford, with Aurora a non-operated working interest partner in the Sugarkane sweet spot.

While DUG Australia was focused on unconventional resources in Australia, it featured a number of U.S.-based speakers who presented learnings from their experiences in developing shale resources.

Aurora is a case in point. The company was founded in 2005 on a $10 million stake by a Perth, Australia, investment group. Thanks to its Eagle Ford position, Aurora now represents more than $1.7 billion in enterprise value. Five quarters ago, Aurora generated less than 4,000 barrels of oil per day (Bopd) out of its Sugarkane holdings. Production topped 15,000 Bopd at the end of the second quarter 2013.

The company concluded a $115 million, 2,700-acre net Eagle Ford transaction in March 2013 that moved the firm from a working interest partner with Marathon Oil Corp. into an operator of 11 wells with 300 potential locations. Aurora will employ a two-rig program in 2013 to drill 14 to 19 wells on 40-acre spacing on its recently acquired acreage while continuing as a working interest partner with Marathon elsewhere in the Sugarkane. The company is currently working on optimum spacing in the Eagle Ford and exploring how to exploit the overlying Austin Chalk formation as a bonus. With $165 million in cash and a $200 million undrawn revolver, Aurora represents the successful culmination of a business model that focuses on early entry resource exploration.

“The liquidity, and much of the financial success, is credited to the Australians in that vision,” Brooks said. “It just happens that the assets are in the United States.”

Brooks was named CEO for Aurora in 2012 after a search to find an American executive to oversee assets in the U.S. since Perth, Australia, is almost exactly halfway round the globe from Houston. That Australian connection made Brooks an attractive evangelist for spreading the gospel of unconventional opportunity to an audience nibbling around the edges of a vast unconventional resource potential in the Land Down Under.

According to Netherland Sewell and Associates Inc., Australia ranks sixth globally in technically recoverable oil shale resources, with 18 billion barrels of oil potential and another 437 trillion cubic feet of technically recoverable shale gas resources, which places the country seventh in global rankings.

“What Aurora has done is something you guys will be able to do because you are blessed with resources inside your own country,” Brooks told attendees. “Where are we headed as a company, and where is Australia, as a country, headed? You’ll see strong organic growth. It’s going to give you revenues. It’s going to generate positive cash flow over time. You’re going to bring in new and interesting formations,” Brooks said.

The effort will come because of Australia’s close proximity to important markets in Asia and India, Brooks said as he outlined a list of learnings from U.S. shale plays. The first learning is that not all plays are created equal. Some shales are too deep, while others too shallow. Some are underpressured. Within shale plays, differences are evident in the volume of resource in place, thermal maturation and recoveries per well.

“Differences can be manifest, not only in the sub-surface, but also as political issues at the surface,” Brooks said, after cautioning Australian operators to band together to magnify their collective voice at the federal and local governmental levels. Surface differences also entail significant variations in operating procedure, Brooks noted, comparing hot summertime temperatures in the South Texas Eagle Ford play to frigid wintertime temperatures in North Dakota’s Bakken shale.

“Water acts differently. People act differently. Efficiencies are different. Safety is significantly different,” Brooks said. “When a company says they are a resource player, I like to know what basin they focus on, and why. Basins are different simply from weather patterns and topography. Some of the challenges they have in the East with the Marcellus and the old Appalachian mountains versus South Texas, which is flat as a table top, lead to different cost structures.”

Additionally, learnings are accelerating. Brooks cited the 13-year cycle that brought the Barnett shale to commercialization and compared it to the Utica, the most recent shale, where land values accelerated from $200 to $500 per acre to $7,500 in 18 months.

“The time compression creates opportunity, but it also creates an immense amount of competitive tension, where you have to get in the field and get your work done in a very efficient and scientific manner,” Brooks said. “But there is a benefit to having a large competitive base around you in that, once the land grab has been made, share your data. You’ll get data back in return.”

That process accelerates play development. Brooks cited experience in the Eagle Ford shale, presenting data that showed how many months it took to reach peak monthly production in individual wells. The peak month production number grew higher as operators became familiar with the play by adjusting the cocktail of proppant and well stimulation techniques. Eventually, peak monthly rates per well flattened as operators solved the technical challenges.

“In the Eagle Ford, it took about three years of drilling and about 700 wells until you started to see peak month production flatten out,” Brooks said. Those wells cost an average $7 million each. He cited an advantage in the U.S. where a large number of independents work under short lease terms. The volume of that operator competition enables the industry to make incremental adjustments on hundreds of individual wells to isolate which variables made an impact on well productivity and collectively move the play forward.

In contrast, Australians have a small number of operators who have large acreage licenses under terms that stretch seven or more years into the future.

“If you are given seven years, and you can do an aerial geo mag study and have three years in which to do it, there’s really not much of a hurry to get things done,” Brooks said. “In the U.S. ,you may only have three years to get a lease drilled, otherwise you lose the lease,” he said.

Brooks also noted that the U.S. oil and gas industry is further advantaged by a large number of private equity players who will partner with operators to finance development to de-risk a play and an equity market that will credit producers for future production as they de-risk acreage.

However, variability in shale plays is a challenge. The best economics come with the best rocks, or Tier I acreage. More acreage in each play falls into a Tier II category, which usually presents opportunity, but has a story to go with it. As for Tier III acreage, Brooks said to avoid it.

Determining which is which via a disciplined de-risking process is the key. Operators have partnered with private equity or joint venture partners to spread financial risk. And once the land grab is finished, operators share information through joint projects to spread geologic risk and maximize learnings. But not everything works. Brooks explained that companies always color code their acreage positions on maps in yellow. “Solid yellow is intoxicating,” he said. “But believe me, if it doesn’t work out, you own it 100%. In many, many of these resource plays, you’ve overexposed capital if you are not in Tier I acreage.”

Brooks identified several positives for the Australian market, including functional capital markets, a large investor base, and significant resources.

“What I think will happen in Australia, and my forecast for you, because you are a very wise group of people on the technology side, is that you are going to compress your learning curve as you do this, simply because of the large acreage blocks that you have,” Brooks said. “You will move up the learning curve a little quicker.”

Contact the author, Richard Mason, at rmason@hartenergy.com.

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