Letter from San Francisco

Tony Bennett may have left his heart in San Francisco, but at a recent oil and gas investment symposium in the city the audience kept its emotions firmly in check. The less-than-enthusiastic crowd at the Independent Petroleum Association of America’s West Coast Oil and Gas Symposium (OGIS), held in September, reflected a financial industry that, judging from the third-quarter drum roll of sell-side downgrades for oil services, has developed ennui on energy.

It was unfortunate, because unlike today’s mega-conferences that emphasize large public companies rehashing their progress in the latest tight-formation oil or gas play, the West Coast OGIS event is a forum for smaller public companies that are promoting tomorrow’s stories. It is an early glimpse at the conveyor belt of ideas imparting vitality to an evolving oil and gas industry.

The San Francisco event also featured one of the larger gatherings of upstream master limited partnerships (MLPs) in a single setting. The consistent yield model of the upstream MLP has come of age with investors. OGIS presenters included eight of the 11 existing upstream MLPs. If you want to know what’s going on in transactions, ask the management team of an upstream MLP. Each of the OGIS eight outlined a favorable climate for the acquisition of mature assets.

“Assets change hands all the time,” Richard Robert, chief financial officer for Vanguard Natural Resources LLC, Houston, told attendees. “The type of assets C-Corps divest are exactly what we’re looking for, so deal flow is not a problem.”

Exploiting old frontiers

The underlying theme at the San Francisco OGIS was industry efficiency. Operators are getting better at what they do, and that evolution is reflected in the fact that news on emerging shale plays is about as scarce as optimism on natural gas. Instead, comments about maximizing recovery in unconventional plays suggest the new frontier in oil and gas is a story of better exploitation of the old frontier.

Multiple presenters outlined how technology is generating new oil from mature regions, whether the setting is the Gulf of Mexico shelf, the Permian Basin, or any one of dozens of plays across the U.S.

Offshore? “You’re not finding the half-billion-barrel fields, or the 300-million-barrel fields, or the 200-million-barrel fields. Those have all been found,” Ben Marchive, executive vice president for exploration at Energy XXI Ltd., Houston, told questioners during an OGIS breakout session.

Instead, Energy XXI is applying horizontal drilling and improved completion techniques to add reserves by increasing incremental recovery out of existing assets in the shallow waters of the Gulf. As an example, Marchive outlined results from EXXI’s Big Sky #2 horizontal test on the West Delta 73 block, south of the Louisiana coastline, which the company acquired as part of ExxonMobil’s $1.012-billion shelf divestiture in November 2010.

Vertical wells in the structure previously generated an initial production (IP) of 1,000 barrels of oil equivalent per day and an estimated ultimate recovery of 350,000 barrels. The Big Sky test, which was completed in September 2012, employed a 1,000-foot lateral targeting 2,500 barrels equivalent per day. Although Hurricane Isaac interrupted work, Energy XXI completed the well for $8.7 million with a 24-hour IP of 3,000 barrels of oil equivalent per day. Marchive’s presentation revealed an 800,000-barrel estimated ultimate recovery.

One week after the conference, Energy XXI inked a joint venture with ExxonMobil to apply similar technology to adjacent properties on the shelf.

Permian Basin

If there was an area demonstrating some heart in San Francisco, it was the Permian Basin. The dusty West Texas region has regained the prominence it held when it was producing 25% of the nation’s daily oil production. A recent series of billion-dollar transactions, some involving majors such as Chevron Corp. and Royal Dutch Shell Plc, which in September 2012 purchased Chesapeake Energy Corp.’s Delaware Basin properties, demonstrate that operators are back in the saddle in a region that has produced oil or gas for more than 90 years.

Out in the high lonesome of West Texas, attractive oil prices and rising drilling efficiency are key factors in a growing regional horizontal play in both the Midland and Delaware sub-basins of the Permian Basin—a point of interest for investors in energy.

The Permian is gaining momentum as operators apply unconventional techniques such as horizontal drilling and multistage fracturing to multiple tight-formation targets. That, in turn, is bringing about a progression in Permian drilling as operators turn from bread-and-butter vertical Wolfberry drilling toward larger yields from horizontal efforts.

“In the Wolfberry, we’ve drilled 70 wells,” said Fred Callon, chief executive officer for Natchez, Mississippi-based Callon Petroleum Co. “We have over 100 locations left, but we’re phasing it out to the extent we think the economics of horizontal are better than vertical.”

Cost pressures are accelerating A&D in the Permian Basin, according to Steve Pruett, senior vice president for business development at Midland-based Concho Resources Inc.

“What has changed in the Permian is that it is a game for the big boys, whether it is a $2-million Wolfberry well or a $9-million Penn shale well, and the smaller independents have trouble playing that game,” Pruett told a standing-room-only breakout session at the conference.

“There are firms like Legacy (Legacy Reserves LP) and EnerVest (EnerVest Ltd.) that are rolling up the mom-and-pops who have mature production and are ready to go to the farm. And then there are a number of private independents in Midland that have gotten sophisticated and are playing the game, but have leased so much acreage and are now seeing the vertical game become a horizontal game. A $3.5-million well is now an $8-million well, so they are saying: ‘Wow, that’s a game for the big boys. I’m either going to have to go to Mr. Private Equity and get some backing, sell down, find a joint-venture partner, which some have done, or drill a handful of wells and sell.’

“So we’ve never seen more deal flow from private independents—and frankly, from smaller public independents that have acreage positions they can’t process.”

While the Permian Basin attracted attention, enthusiastic support for natural gas—at least in the short term—was nowhere to be found. Michael Watford, chief executive officer of Houston-based Ultra Petroleum Inc., started the conference with a sobering review of an oversupplied natural gas market.

“We’re deferring completions and we’re cutting capex as fast as we can,” Watford told the conference. “You just can’t turn this stuff off quickly is the message.”

Ultra began the year with $925 million in capex but will exit 2012 below $625 million. In Wyoming, where Ultra controls 53,000 net acres in the prolific Jonah-Pinedale dry-gas play, the company reduced its rig count from six units to two in early 2012 at a cost of $10 million in cancelled contracts.

“I think we’re typical of all the other companies in the industry. You haven’t seen the production cuts that are coming, because when you cut capital it takes a while to wind down,” Wat-ford said.

And that observation led to a startling prediction. “Much like gas prices went down very quickly, they can go up very quickly,” Watford said. “Most companies are going through their capital budget forecasts for 2013 right now. You are not seeing any allocated capital for drilling dry-gas wells. By the time supply comes down in 2013, you won’t see capital go back into gas until 2014. That means you won’t see a production increase until 2015. So here comes $6 gas.”

Meanwhile, Plan B for natural gas companies was evident in a presentation by Gastar Exploration Ltd. Chief executive officer J. Russell Porter outlined a stealth liquid play in the Midcontinent in which the Houston-based company had blocked up 25,000 acres as a 50% partner. Gastar has drilled one well in the play, plans to complete two more by year-end, and will spend up to $40 million on acreage acquisition and drilling in 2013. Porter said the last two of the nine wells Gastar’s partner had drilled in the play generated IPs of 600 barrels of oil equivalent per day.

“If we see that sort of performance from the wells we’re drilling, we’ll be off and running and trying to get as much acreage as possible in this play,” Porter said. “It will certainly change the outlook for Gastar and give me a reason to take the ‘gas’ portion out of our name and become anything other than Gastar.”

Despite concerns about gas prices, costs and other factors, it would be wrong to say there was no enthusiasm in San Francisco. The Giants clinched a division title in time for OGIS, and civic pride was reflected in the modest bounce-in-step among locals navigating the crisp evening air on their way to a baseball nightcap. Back at conference headquarters, in the stately Palace Hotel, financial attendees were waiting for a name player to step up to the oil and gas plate and start a pennant-winning rally.