Friday, August 9, 2013

Goodrich Earnings Call

Goodrich Petroleum presented their quarterly results on Wednesday with some very good news regarding the TMS.  Here are some of the highlights:

  • will close the Devon transaction in a few weeks
  • Sinopec, Devon's former partner, has elected to stay in the project
  • the Goodrich CMR/Foster Creek 20-7H-1 is almost to total depth
  • now planning to reallocate approximately $15 million of capital expenditures in the fourth quarter of this year from the Eagle Ford Shale play to the TMS
  • With continued success, we expect further acceleration of our TMS development activities in 2014
  • we can't help but be optimistic about the play at this point, as we see continuing improvement and repeatability of well results
  • costs are trending down, thereby establishing very attractive economics
  • The Smith well, which is approximately 5,400 feet of usable lateral with 20 successful frac stages, has averaged approximately 1,000 BOE per day of our 12/64-inch choke over the recent 8 days after reporting a 24-hour average rate of 1,045 BOE per day
  • The EnCana-operated Anderson 17H-2, which as Gil stated earlier, had the record IP to date of 1,540 BOE per day, had a similar frac design to the Crosby and a similar lateral links to the Smith well. Both of these wells had 95% to 96% oil cuts. The Anderson 17H-3 is in early flowback, and we expect that result to be good as well.
  • our Crosby well has produced in excess of 100,000 barrels equivalent in 5 months, with an approximate 92% oil cut, and is still producing approximately 375 BOE per day currently, as we near the end of the 6 months of normalized production
  • If you spot 375 BOE per day on our 800,000-barrel equivalent type curve at 6 months, you will see the decline has been flatter than expected, and we continue to trend above the curve. If you plot 100,000 BOE on our accumulative production curve at 5 months, you will see that Crosby is well above any other well in the fields and reached 100,000 BOE in half the time as compared to the better Bakken wells.
  • Our current plans are to spud 3 additional operating wells by the end of the year
  • seeing well costs come down in the TMS, as our Smith well was drilled and completed for approximately $13 million. We continue to believe we can drive our costs down over time to the $10 million range through better drilling efficiencies, pad drilling, zipper fracs and a more competitive service company environment.
  • even at current well costs, the economics are compelling in the play and very similar, if not superior, to what we see in the Eagle Ford. Our 800,000 BOE curve at $90 WTI produces a 56% internal rate of return, with 15% to 20% incremental IRR for every million dollars of savings or $10 movement in oil prices.
  • The economics are driven off of very attractive production rates, as well as certain inherent advantages of our other oil plays, such as our production stream is 90% to 96% black sweet oil, priced at approximately $2 off of LLS, and we continue to receive north of $100 per barrel; our gas has a high BTU content, with approximately 80 to 100 barrels of NGLs per million cubic feet produced; we have 24 to 30 months of severance tax relief in both states of Louisiana and Mississippi; our royalty burdens averaged approximately 19% across our combined acreage block versus much higher in other plays; and we are dealing with cooperative landowners and efficient state agencies for regulatory purposes.
  • our near-term focus is, as we think it should be on the TMS, as recent results in our pending acquisition provide a tremendous catalyst for production reserve and NAV growth. Given the current state of the play, we fully expect further acceleration of TMS activity as we move forward and into 2014
  • what's important to look at on the Anderson 17H-2 is just with a very slight change in choke, you can see the potential impact of volumes going forward
  • I think our first order of business with our new partner (Sinopec) is to get out and drill some wells jointly and to hopefully demonstrate our operational capabilities and certainly, hopefully, some successful wells together. And at that point, if they have some interest in expanding that position, we certainly would be all ears and willing to listen to them.
  • Obviously, one of the objectives is to try our wells, design our recipe on that acreage and see if we can turn that around. And having Sinopec hopefully participate with us, as we expect for a third interest, helps share some of the burden of that. And so we're going to move. And I would say, the move in the fourth quarter and the majority of our TMS activity in the fourth quarter will be on formally Devon acreage.
  • One of the benefits that we have gained from the Devon transactions, we did pick up core data on all of the Devon wells in which they took course, which materially added to our knowledge base from a geologic perspective. We're not saying -- and we've said this publicly, we're not seeing anything more than what we would call very nuanced differences in geology and mineralogy and rock properties including clay percentages and types of clay. So we don't see anything -- and I guess we should back up and resistivity, the high resistivity  we do think is an important feature. A number of different things contributing to that. We probably see the highest resistivity  quite frankly, across the southern part of the play in Louisiana, right along the southern part of the Mississippi-Louisiana border there. So we're optimistic, we need to get down there and demonstrate what we think it is capable of. But we're not seeing anything, at this point, that rules out any particular part of the acreage. The geologic changes or some nuance is small. And in fact, if you look at the Crosby, it's probably got the highest -- one of, if not the highest, clay content of any of the course we've seen across the play. So everything is open and on the table in our mind.
  • Severance tax reduction: It's 30 months or until the well pays out. And we believe that's on the order of $750,000 to $800,000 of benefit to the well. So very important and very meaningful.
  • No question the hybrid frac, in our opinion, work a lot better than slick water. And as Gil said, the clay stabilization fluid that we pump, you cannot argue is working extremely well. The first one to pump that particular type was the Crosby well. And when you look at lateral links and profit amount pumped and how those wells were completed compared to others, that well is certainly superior to the other ones. So we think that's an important ingredient to put in the recipe.
  • When asked about how much acreage you, potentially, if you were having to handicap it, to maintain, I think the comment was at least 75% of that was either shallow, above 14,000 feet through vertical depth, so your well costs would be lower, or in -- what we view could be core and less on the fringe of the outskirts. So that was basically just an attempt to handicap it if we could. We don't see anything but subtle differences when you look at core data, not only from the Crosby all the way into the Devon acreage package. We think it's all in the completion recipe. So no, nothing has changed. Certainly, once we got into the data room and we were able to review the data, we became more positive about the Devon acreage. But no, we were just trying to handicap at that point in time. But as Gil said, we can't rule out any of the acreage at this point.
  • the Crosby has higher clay content that almost any well out there, and you look at how that well has performed versus the other wells, knowing that we pumped this particular type of stabilizer and it's just the fluid that you include in your frac fluid, you can't rule out the fact that that well has performed exceptionally well. And it's just basically a pump to keep the expendable clay portion of the overall clay from swelling. And if you can keep it from swelling, it becomes less sponge-like, you get a more effective frac, you get your fractures propagated and held open, it doesn't want to close up on you. So it's a fairly simple, I would say, process. And we had quite a bit of lab work done and analysis done, and we felt like this potentially could be as much as 75% more effective -- at least that's what some of the lab work had indicated. So yes, we're pleased with it. And of course, the not going in was whether the clay would impact these -- the production, and we're not seeing the impact of clay on any of the wells. But certainly, the Crosby, and these last 2 wells, are performing exceptionally well with the pump.
  • the Crosby is outperforming our 800,000-barrel curve. The oil cut is about 92% there, and that's been fairly consistent
  • I would say that not that many of the people view the play the same way we do. And when the price got down into our strike range, we went after it. And I will let everybody else comment for themselves about why they didn't pursue it.

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