Wednesday, May 7, 2014

Goodrich Petroleum Earnings Call

The highlights from the transcript of the earnings call:

-currently operating 3 rigs 
-As many of you are aware, the early wells drilled in the optimal lower landing target experienced drilling problems related to wellbore instability and a specific interval of the TMS just above the lower target. To mitigate these early time drilling challenges, we've revised our go-forward plan of drilling this unconsolidated or rubblized zone at approximately a 70-degree angle rather than the 80 to 85 degrees, as many of the early type wells have been drilled. While a 10 to 15-degree change in angle may not sound like a lot, in reality, we have reduced the area of traverse or contact with the unstable, highly consolidated or rubblized zone from approximately 135 feet of contact to just 25 feet. This change has dramatically reduced wellbore instability issues and allowed us to drill this section and land in the lower target without significant drilling problems. 
-Our recently completed wells, the CMR 8-5 and Blades 33-1 were drilled in this manner, as were the 3 most recently drilled wells, where we have recently moved into completion mode on the C.H. Lewis 30-19, Nunnery 12-1 and Beech Grove 94-1 wells. We believe this is the right template and is our design and plan going forward. 
-By landing in the lower target and reverting back to standard drillable composite frac plugs, we've also been able, thus far, to eliminate any of the issues we and others experienced previously with casing deformation and difficulty drilling out frac plugs when landing in the upper target. This process and completion design worked well on the CMR and Blades wells and will be the same procedure used on the Lewis, Nunnery and Beech Grove wells, each of which we expect to be completed by the end of this month. 
-Our recently completed Blades well was significant for a number of reasons, including as a delineation well, as it is the most southeastern horizontal TMS well drilled to date. Likewise, our upcoming completions will also be important as the Nunnery will be the most northeastern well on the play thus far, and our Beech Grove will be the most southwesterly well drilled using our completion design. The completions of these wells and our increased phase of development with 3 rigs running, as well as the increased level of industry activity, is advancing the development and delineation of the play at a significantly faster pace than even a few months ago. The faster pace of development is a benefit to all operators in the play, and I expect we will soon cross the milestone mark of 50 modern-era horizontals drilled by the industry in the TMS. The increased activity is also advancing the ball faster towards full delineation of the play, moving us to or very close to an inflection point in the play's development. With the play's inflection point upon us, our current plans include the initiation of a joint venture process in the TMS in the second half of this year, which would include bringing in a new JV partner or expanding our existing relationship. The next few months will be very interesting and exciting times for the TMS. And now I'd like to turn the call over to Rob Turnham. 
-we tweaked our completion methodology on the Blades, which was a 5,000-foot lateral, by reducing the frac interval and slightly increasing the profit amount per stage, which yielded a higher production rate per linear for the lateral. 
-when you analyze core and other subsurface data, we only see minor differences in the rock quality across our entire block and the difference in well results are primarily been driven by landing target and completion recipe. 
-We continue to update production from the key wells and plot against our 600,000 and 800,000-barrel type curves 
-we own a non-operated interest in a couple of wells where pump depths and size of pumps have been adjusted, yielding much better rates and flatter profiles in further support of our type curves and approximately 2 years of production 
-Well cost in the play will continue to come down as we shave days off of our drilling curve, get more competitive pricing from service companies with increased capacity in the field due to higher activity levels, and pad drilling, which we expect to begin on a limited basis shortly. Depending on lateral length and number of stages, we see a path to a potential $11.5 million completed well cost by the end of the year and further reductions next year towards our target of $10 million in development mode. Also, with the added activity from other very capable operators in the play, we will each benefit from each other's activities as we're sharing information with a common goal of best practices as soon as possible. To that end, you will see other operators with very good drill times on recent wells, and we expect that to continue. 
-we will be in a position to entertain JV options in the second half of the year -We're currently frac-ing our C.H. Lewis well which is 6,600-foot lateral with 26 planned frac stages. We will put our Blades completion recipe on the well. 
-We're also scheduled to frac our Nunnery and Beech Grove Wells in May. 
 -We are currently drilling our SLC well in West Feliciana Parish, Louisiana 
-plans to commence drilling operations in the coming days on our Bates and Denkmann wells in Amite County, Mississippi. 
-the Blades well at 5,000-foot lateral, clearly, as you can see, it's currently tracking our 800,000-barrel curve 
-our CMR is probably more closely tracking our 600,000-barrel curve -update of our 600,000-barrel curve with the 2 oldest wells, the Anderson Wells. They've tweaked the artificial lift a bit. Those production rates are up and back up like where we thought they would be or sitting right on top of our curves 
-we'll start to see some of the economies of scale from pad drilling sooner rather than later
-we're going to be back up in the Crosby area, Foster Creek, Crosby area in Wilkinson County. And we have a plan for a 2 well pad up there. The benefit of the 2 well pad is, obviously, from a cost standpoint. But you form these 3 section units. You put the pad in the middle. You drill a tow-up well and a tow-down well and, obviously, capture acreage a little bit quicker, but forget the benefits of the cost reduction. So that -- the 2 wells will be -- we'll have several of those in 2014. And then, the multi-well pads will commence in 2015. 
-we're thinking that ultimately it could be 80 100-acre spacing, but we're probably thinking 160-acre spacing initially. So call it 1,320 feet between well bores or 4 wells per unit. And that would be -- we think we'll down-space from there in the future 
-the next few wells are planned to pump about 550,000 pounds of proppant per stage. As we've said before, we are targeting about 6,000 plus feet of lateral. As Rob said earlier, we think that longer laterals is the better way to go, but we're very, very mindful of cost per well at this point. And we don't have the full answer to how much incremental reserves a longer lateral with a similar type completion design would yield. So we're going to kind of target that 6,000 plus and let each well be dictated upon exactly what happens as we get at or around that 6,000 foot of lateral and try to be mindful of not spending extra days unnecessarily. And -- but you can think about us being plus or minus around 6,000 for the next few wells 
-I think the Blades well was 36 days. Obviously, that was kind of 9 days under AFE 
-A lot of our improvement, we think, is going to come in the vertical portion of the wellbore. We can, as Gil said, reduce the flat spots when you're running casing, drill the vertical well faster, increase your rate of penetration drilling curve. We've been pretty pleased with the lateral drilling. Knowing that you're -- we're staying within a 10-foot window, you can only push the rate of penetration so much. So I think our improvement comes in the vertical portion of the wellbore. With the increased activity level, we are already seeing more bids. And of those bids, they're more competitive. And I think that only increases with the increased rig count in the field. So we're expecting to see a reduction in costs, I would say, other than our frac costs, which are basically locked in for 2014. And those are about 20,000 the stage less than where we were in 2013. 
-for every day you shave, it's a $100,000 off the drilling curve. The other goods and services we think are going to contribute quite a bit prior to pad drilling 
-we have used snubbing units to drill out frac plugs in the last couple of wells. We think that's the safer route to go. However, we've also seen a couple of wells recently that were not Goodrich-operated wells drill out their frac plugs successfully using coiled tubing, which we have done before, our Crosby well was of coiled tubing. I think, ultimately, you're going to see us move towards coiled tubing drill out. We -- admittedly, we're a little gun shy after the problems that we had. We want to put belt-on suspenders and we've done the last couple of wells of coiled with that with snubbing units. Yes, we are monitoring very closely the maximum treatment pressures to make sure we don't do anything that might put undue stress on the pipe to further mitigate pipe deformation. We happen to believe that most of that, however, when we look at the data across all of the wells that have been drilled so far, is really more around landing target than necessarily maximum treating pressure on any given stage. But that being said, we're trying to stay at about 1.0 gradient on our treating pressures 
-the only wells that have had any problems at all thus far, David, drilling out plugs have been upper target wells. About 65% of the upper target wells have been drilled in the play, thus far it had some degree of difficulty getting plugged up. And that would be in a combination of both snubbing unit drill-outs as well as coil tubing. We don't think that, that will determine. Determine is whether or not you deformed your pipe in any way shape or form. And if you have and you've done it to a strong degree, it probably doesn't really matter whether they're using a snubbing unit or a coiled tubing if you can't get down the pipe lateral -we're targeting the 6,000-foot laterals. And we think we can get to that number with multi-well pads, zipper fracs, all those things that we mentioned. So yes, we're still targeting the 6,000-foot laterals. Ultimately, we think we can get there to $10 million just -- and still get the full lateral length. 

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