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Vol. 17, No. 37 Week of September 09, 2012
Providing coverage of Bakken oil and gas

Most plays ‘insignificant’

Only 2 horizontal plays matter; EOG to move Permian capital to Bakken, EF

Kay Cashman

Petroleum News Bakken

EOG Resource’s top executive Mark Papa raised a few eyebrows Sept. 4 when he told attendees of Barclays energy conference that only two horizontal liquids plays in the U.S. matter — the Eagle Ford and the Bakken. The rest are “insignificant” in terms of future U.S. production, Papa says, including those his company is invested in, such as the Wolfcamp, Permian and Barnett plays.

In fact, in 2013, it is “likely” the Houston-based company will be “stealing some capital from the Permian and … Barnett combos” for company operations in the Eagle Ford and Bakken, Papa said.

What has changed from Papa’s comments in EOG’s second quarter earnings conference a month ago when he said there were only three “consequential horizontal oil plays in North America — the Eagle Ford, Bakken and Permian”?

And what is different from earlier this year when he referred to the Wolfcamp shale play as the “fourth leg” in EOG’s strategy, asked one attendee: “Has something changed to make you want to allocate more rigs to the Bakken and the Eagle Ford?

NGL prices the issue

“Yes,” Papa replied, “the biggest change from six months or a year ago is our perceived change in NGL prices,” noting “a year ago we had relatively strong natural gas liquids prices and that made the economics of the Wolfcamp or the Barnett combo plays more attractive.”

But today, Papa said, EOG’s executives are “not as sanguine about what’s going to happen in 2013 with NGL prices.”

Combo plays are “comprised of one-third NGLs, one-third dry gas and one-third oil, unlike the Bakken and the Eagle Ford which are comprised primarily of oil in the range of 80 to 90 percent, and the rest of it is dry gas and NGLs,” he said.

EOG’s strategy is to continue to optimize the Wolfcamp, “but it’s not a play that gives us as good an economic return as either the Bakken or the Eagle Ford, particularly when we can get LLS (Light Louisiana Sweet) prices for those products,” thanks in part to being able to deliver both by either rail or pipeline to lucrative markets.

Permian, Wolfcamp and other combo plays have “decent” economics, but they are “captive to what happens to NGL prices,” Papa said.

Misleading nature of boe

He warned investors not to be fooled by the growth of barrels of oil equivalent, which include natural gas and can be misleading.

In touting EOG’s financial prowess, he mentioned its “history of 13 dividend increases in 13 years,” and noted its current “26 percent net debt to cap.”

Papa also cautioned against massive growth.

“It would be very easy with our assets to show this monstrous oil growth, while simultaneously blowing up our balance sheet. But we have been very cautious to say we want to have monstrous oil growth while preserving our pristine balance sheet. And so we have artificially imposed upon ourselves a maximum net debt to cap ratio of 30 percent because we want to preserve our A-minus and A ratings from S&P and Moodys. … That’s the game plan.”

Pointing to a chart that shows U.S. horizontal oil growth by play from 2005 to 2012 (adjacent to this article), Papa said, “The point we make is, there are only two plays that make a difference on a national scale — the red and the turquoise. The Eagle Ford and the Bakken. There’s been a lot of sell-side news and specific company news about plays like the Woodford, the Mississippian, the Niobrara, and so on and so forth but they barely make a spec on this chart.”

“Our prediction is that over the next five years they (non-Bakken, non-Eagle Ford plays) will barely make a spec on this chart. And so for all the news that they are generating, they’re not going to be significant players on a national scale,” he said.

Next, he pointed to a chart that showed which companies produced the most crude from horizontal plays in the U.S. EOG topped the list.

“As it stands right now, by a 2 to 1 ratio, EOG is the largest producer. … It’s no horse race at this point in time,” Papa said.

Eagle Ford still Papa’s favorite

Papa’s favorite horizontal liquids play in the U.S. is the Eagle Ford, possibly because almost all of EOG’s 574,000 net acres in the Texas play are considered “premier” acreage in the oil window, while only about 90,000 of the company’s 600,000 acres in the Bakken are in the “sweetest” part of the play.

While EOG has not revealed its internal rate of return in the Bakken, Papa did repeat what he has said in the past about the Eagle Ford, and that is “on a direct rate of return … about 80 percent after tax” on oil.

And that’s partly because it gets a good price for its crude, and because its saving roughly a half million dollars per well by supplying all its own frac sand from its own mine.

He did, however, talk about oil recovery rates in the Bakken, putting them at approximately 10 percent versus 6 percent for the Eagle Ford.

Although not at the expense of the Eagle Ford, since EOG released its first quarter results Papa has been increasingly bullish on the Bakken, saying in August that the company was “considerably more optimistic about the next 10 years of this play than we were a year ago.”

EOG President William Thomas best explained the change in attitude in August:

“Last quarter, we advised you that we are more optimistic about the Bakken and Three Forks (both part of the Bakken petroleum system) as growth vehicles than in the past several years for three different reasons,” he said, providing updates for these reasons.

“First, 320-acre infill drilling in the Bakken core continues to generate positive results,” including several new infill wells.

“The reason we’re so excited about EOG’s core area down-spacing is that our 90,000 net acre core is the sweetest spot in the entire Bakken, and it is where 22 of the 30 best Bakken wells in the entire play have been drilled. So this is a rich hunting ground for down-spacing. With our Bakken acreage now held by production, we are shifting our focus to increasing the recovery factor with down-spacing and improved frac technology,” Thomas said.

“Second, we continue to have great results in our Antelope extension area, which is 25 miles southwest of the core. Typical recent wells here are the Riverview 100-3031H and 04-3031H, which tested at rates of 1,834 barrels of oil per day and 1,863 barrels of oil per day plus rich gas from the Three Forks and Bakken, respectively.”

“The third growth area is our Stateline area, where we recently completed the Stateline 08-3328H in eastern Montana at 1,260 barrels of oil per day. With confirmed success, we estimate 200 potential locations in this area. As you can see, we have plenty of room to run in the Bakken and Three Forks. Additionally, we continue our Bakken Core waterflood pilot project, and we expect to have preliminary results by year end,” Thomas said.

Improving recovery

At Barclays conference in September, Papa confirmed part of EOG’s strategy for the Bakken and Eagle Ford is to improve recovery factors, thus getting a “dramatic increases’ in reserves.

For secondary recovery “the Bakken pilot (started in mid-April) is a lot more advanced on secondary recovery (than the Eagle Ford). That one’s pretty far along and from the results of lab testing on cores we feel pretty good about at least the lab results from the Bakken.”

“What would it take to get EOG interested in natural gas,” asked an attendee.

“It would probably take a gas price of $5 or $5.50; but more importantly, we would have to believe the gas price would be sustainable,” Papa said. “Let’s say we had a bitter cold winter and gas prices spiked to $5 or so, our issue would be: ‘Is that just a temporary spike that would stimulate a whole bunch of drilling, and then within a year gas prices would be back at $4 or $3.50?’ For us we’d need to see a structural change in gas demand. … Something significant, like degradation in coal-fired power plants … a significant reduction, a permanent reduction.”

Kitimat?

The final question of the day was, “where do negotiations stand on the proposed Kitimat LNG export facility,” a producer-owned development in which EOG holds a 30 percent interest with operator Apache Canada, 40 percent, and EnCana, 30 percent. Natural gas for Kitimat LNG would likely be sourced from many different producing areas in British Columbia and Alberta, including the Horn River Basin, EOG has said.

“We’ve been pretty quiet vis-à-vis Kitimat,” Papa replied. “In our earnings call in August we probably devoted all of one sentence to Kitimat.”

The issue on Kitimat “is really the project is not going to go anywhere until the consortium gets an oil index contract with a Far East buyer for a majority of the off-take, and that has gone certainly slower than any of us expected. I wouldn’t even hazard a guess to the timeframe as to how that’s going to move forward,” he said.

“So what I tell people is, EOG is a heck of a company if Kitimat never happens. It’ll be a positive augmentation if Kitimat does happen, but don’t buy EOG on the basis of Kitimat because it’s still kind of a long putt.”



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