Goodrich Petroleum Corporation
Q1 2014 Earnings Call Transcript

Published: 6 May 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the Q1 2014 Goodrich Petroleum Corporation Earnings Conference Call. My name is Rachel, and I'll be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would like to turn the call over to Daniel Jenkins, Director of Corporate Planning and Investor Relations. Please proceed.

[Daniel Jenkins:]

Good morning, everyone, and welcome to our first quarter earnings conference call. I would like to begin with the introduction of our management team on the call with us this morning

[Walter G. Goodrich:]

Thank you, Daniel. Good morning, everyone. Thank you for joining our first quarter conference call. During the quarter, we accelerated our transition into the Tuscaloosa Marine Shale play. During the quarter, we also added an additional operated rig to the TMS, where we are currently operating 3 rigs. Our [ph] transition period from late last year, where we reduced activity in the Eagle Ford Shale and began to increase TMS activity, did have some impact on the quarterly numbers that we reported this morning, we also made significant progress, particularly from an operational and best practices standpoint, in the TMS during the first few months of this year. Rob will give you more color and details on the operations and the status of our development activities, and Jan will give you more details on the quarterly financials in just a minute. Therefore, I will stay on the TMS and provide a few updated observations. On our last conference call in February, I outlined several significant issues and challenges we were dealing with at the time relating to specific drilling challenges and post frac completion problems. While I will not recite each of those issues in detail this morning, I would urge anyone not familiar with them to read a copy of our conference call transcript from last quarter. 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.

[Robert C. Turnham:]

Thanks. As Gil stated, the level of activity in the TMS is an all-time high, with 6 to 7 rigs running currently and more to come. We feel that our recent Blades well result in Tangipahoa Parish, Louisiana at 1,250 barrels of oil per day was an inflection point for the play, in that the well was drilled in record time without issues and we saw very consistent result to the best well in the field, which is our Crosby well, approximately 50 miles away. As we previously stated, 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. The Blades well also opened up an area that previously had not had a well drilled, which expands our core position. The Blades well also supports our thesis for other acreage acquisition last summer, that 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. As we've stated before, you can't deny the resource potential of the TMS when you look at the wells that have been drilled and stimulated effectively. We continue to update production from the key wells and plot against our 600,000 and 800,000-barrel type curves, which you will find on our updated management presentation posted on our website this morning. In addition to our operated wells performing very well, 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. As a reminder, we have shaved on average 13 days off of our drilling curves in the Cotton Valley, the Haynesville and Eagle Ford plays, and expect at least that in the TMS over time. As consistency of results and well costs have and will continue to come down on the TMS, we are seeing a much higher interest in the TMS, not only from investors, but from industry. And as Gil stated, 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. Following up on what Gil said, the Nunnery location is a northeast extension from our Smith C.H. Lewis area in Amite County, Mississippi, and the Beech Grove is in East Feliciana Parish, Louisiana in the southwest portion of our block. We are currently drilling our SLC well in West Feliciana Parish, Louisiana, which is a further extension to the west, with plans to commence drilling operations in the coming days on our Bates and Denkmann wells in Amite County, Mississippi. In the Eagle Ford, we have 1 rig running currently with plans to drill 9 wells off of 3 separate pads. We have drilled 3 Burns Ranch wells to date, our 56, 70 and 71 wells, all of which are scheduled to be frac-ed late May. We're currently drilling our Gemini 4 and Gemini 5 Wells, which we expect to frac later in the second quarter. Moving to the quarter. Capital expenditures totaled $55.8 million, of which $45.3 million was spent on drilling and completion of wells, $5.8 million on leasehold acquisition and extensions and $4.7 million on facilities, capital workovers and other miscellaneous expenses. Our rig count, capital expenditures and production will begin to accelerate as we have guided to $90 million to $110 million of CapEx for the second quarter and had several TMS and Eagle Ford wells getting completed in May and June, which will provide a significant ramp in production. Production for the quarter totaled 6.5 Bcf equivalent or an average of approximately 72 million cubic feet equivalent per day, with oil comprising 32% of volumes and 65% of revenues. As many know, we exited the year with no rigs running in the Eagle Ford and brought a rig back in February. However, this transition into the TMS clearly affected volumes in the quarter. We were limited to 3 gross, 2.6 net well completions in the quarter, all of which were in the TMS. But 2 of the 3, as previously reported, had mechanical issues, being the Huff and Weyerhaeuser wells. Oil production for the quarter was also negatively impacted by shut-ins in the Eagle Ford on certain wells for sand cleanout operations, which are now back online. The rate of growth in oil volumes will accelerate beginning late the second quarter due to 6 TMS and Eagle Ford wells being frac-ed in May and early June, which will tee us up for very robust growth in the back half of the year. And now I'm going to turn it over to Jan to walk you through the financials.

[Jan L. Schott:]

Thank you, Rob. Good morning, everyone. I will cover a few items on the financial side. Revenue for the quarter totaled $51.8 million, an increase of $4.7 million or 10% over revenues from the comparable period last year and $1.2 million or 2% higher than revenue for the fourth quarter of 2013. Our first quarter average realized prices, excluding the impact of realized loss on derivatives, were $98.27 per barrel for oil and $4.13 per Mcf for natural gas. For 2014, we have a total of 3,800 barrels of oil per day hedged at a blended price of $93.65 and 30,000 MMBtu per day of gas hedged at a blended price of $4.76. Our plan is to continue to layer on additional oil derivatives as we increase oil production during 2014. We will also continue to watch natural gas for additional opportunities to hedge portions of our 2014 and 2015 natural gas production. Please see our website for a slide on our current derivative position. Moving on to expenses. LOE per Mcfe this quarter was $8.6 million or $1.33 per Mcfe. The first quarter includes $2 million or $0.30 for workovers primarily in the Eagle Ford Shale. The first quarter also included about $0.9 million associated with wells purchased in August 2013 and wells we brought online in the TMS. As we have stated before, as we increase our oil production, we would expect our LOE rate per unit to gradually increase over time, with oil production representing 32% of total production in the first quarter. DD&A per Mcfe was $4.51 for the quarter compared to $4.38 last quarter and $5.84 for the prior year quarter. We would expect the overall company DD&A rates to trend slightly higher next quarter as oil production continues to increase as a percent of total production. G&A cost came in at $8.9 million, $1.38 per Mcfe this quarter compared to $1.57 per Mcfe in the prior year quarter. About $0.36 or 26% of the first quarter rates represents noncash, stock-based compensation. We're projecting a 0 tax rate for the full year of 2014. We ended the quarter with $0.8 million in cash and $10 million drawn on the revolver, providing about $260 million in liquidity at quarter end. In April, our borrowing base was reset to $250 million, primarily due to lower bank deck natural gas pricing and delays in new well additions, with the transition of capital from the Eagle Ford Shale to the TMS, as Gil and Rob both mentioned. However, after the adjustment, we continue to maintain liquidity at $240 million. The next redetermination of our borrowing base will occur in October 2014 based on our midyear reserve report and should benefit from TMS well results in the first half of 2014. We have included reconciliations on the last pages of our press release for all non-GAAP measures to the closest GAAP measure. Please refer to these reconciliations for more detail. We plan to file our first quarter 2014 10-Q with the SEC later today. Please see our 10-Q for a more detailed financial discussion. With that, I will now turn it back to Gil for some closing comments.

[Walter G. Goodrich:]

Thanks, Jan. We believe the increased activity in the TMS and additional wells drilled will be very important to the play. And we are excited about the play overall and our development over the next few months. With continued success, you will see continued increase in activity and much more significant impact on our financial and operating results coming from the TMS. Rachel, that concludes our prepared remarks. And we're now happy to turn it back over to you for questions.

[Operator:]

[Operator Instructions] Your first question comes from the line of Neal Dingmann of SunTrust.

[Neal Dingmann:]

Say, just color, Gil, or just wanted maybe a follow-up. I noticed on, I think, it's Slide 13 or so, the one that shows your TMS cumulative production. And obviously, what jumps out is just the, obviously, the 2 newer wells, the Blades and obviously, the CMR, how they're doing initially. Again, if you or Rob could maybe comment about your thoughts on that. Is that around some of this new completion design, is it -- how you're -- is it the spacing? I'm just trying to get an idea of why these 2 are sticking out like that?

[Robert C. Turnham:]

Yes. Obviously, good news, Neal, is the Blades well at 5,000-foot lateral, clearly, as you can see, it's currently tracking our 800,000-barrel curve. Very excited about that. Think it's likely a combination of consistent well rock qualities, as well as a slight tweaking to the completion recipe. But obviously, to track something that's very similar to what we saw in Crosby, a good 50 miles apart, 48 miles apart, is very encouraging. And the CMR is a shorter lateral also. I think, over time, we'll just have to see how those curves compare. Obviously, lateral -- longer laterals feed in over a longer period of time. But it's all about the rate of return you achieved from the lower well cost drilling shorter laterals. So I think we'll just need to continue to monitor that. But obviously, very positive development to have short laterals, very good well results. I think our CMR is probably more closely tracking our 600,000-barrel curve than the 800,000-barrel curve. But it's been very positive flowback so far. And I think one of those meaningful things on the new slide deck is the 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. I think that's pretty meaningful because we've had some people certainly want to understand what was going on with those wells. And we've been talking about artificial lift and the need to tweak it. And certainly, we've seen a very positive response to the deepening of the pumps and the rightsizing of the pumps.

[Neal Dingmann:]

Rob, and then the follow-up, you mentioned just on this last comment about your cost, does that include -- does that assume that you'll be getting a number of these down into pad drilling? Or is that 11.5, assuming I guess, number one, with or without, and then number 2, I think are you going to basically do a couple of pads this year or what's the thoughts there?

[Robert C. Turnham:]

That's right. That includes kind of 2 well pads. Full development mode is going to be 4 or more wells per pad, and that's where you really drive your well cost down further. But we're -- in fact, we're drilling our first well off of an existing pad, which is going to be a southern extension off of the C.H. Lewis well. And that's about to come probably within the next couple of months. So we'll start to see some of the economies of scale from pad drilling sooner rather than later.

[Neal Dingmann:]

Okay. And then, last one, if I could. Just I know it's very early, on the proposed JV, but your thoughts, for you or Gil, when you would look at this. Is this something you would assume and think about doing on any of the acreage or is there just sort of certain acreage you would focus on?

[Walter G. Goodrich:]

Yes, Neal, this is Gil. I think we'll begin the process, as I said, later this year. And I think we're pretty open to how it might be restructured. Valuation, obviously, will be the key driver. We do intend to continue to operate the vast majority, if not all, of the acreage. So with the footprint we've got plenty of flexibility to how we might add up a piece or just bringing something in across the board or, as I said, expand with the existing part we've got. So lots of options there.

[Operator:]

Our next question comes from the line of Brian Corales with Howard Weil.

[Brian M. Corales:]

Just kind of looking at production and kind of going forward, can you maybe comment, don't have to be exact numbers, but ballpark, I mean, the number of completions or maybe wells brought online in kind of the first half for the TMS versus what we're going to see in the second half?

[Robert C. Turnham:]

Yes, I can do that roughly for you, Brian. We obviously had 3 gross, 2.6 net wells in the first quarter. 2 of the gross were the hubs and the warehouses which we, obviously, got reduced production rates from. Since then, we've had the CMR and the Blades well, obviously, that are going to be second quarter events. We are frac-ing the C.S. Lewis now. We're probably a few stages into it, that's a 26-stage frac. So that's going to take a little while. Then we'll drill the plugs out and put that well on production. So call it mid-to-late May before we have rates on that one. And then, we start frac-ing our Nunnery. When we're through with the Lewis, we moved to the Nunnery. And, we'll start that process. And then, late May, we start frac-ing the Beech Grove well. So really, when you bake in roughly a week to frac, a week to drill out plugs and then a week to hit peak rate, you can see that 3-week delay is really pushing a lot of these volumes towards the tail end of the second quarter. So really, what we're going to see is a major ramp up going into the third quarter. And from there, you have the acceleration, you have the multiple wells from 3 rigs continuing to get completed. So all along, we've tried to guide to back-end loading, probably didn't do quite as good of a job. But if you're looking at 10 to 15 wells in the second half of the year versus much, much less, first half. And hopefully, you don't have any of the Huff plug issues or the Weyerhaeuser plug issues to deal with.

[Brian M. Corales:]

That's helpful. And then, with the JV process, I'm assuming this is going to be a formal process. Would you wait to potentially add additional rigs until this is done? Or do they have nothing to do with each other?

[Walter G. Goodrich:]

Yes, Brian, this is Gil. I think, mainly, we want to see this next handful of wells that are kind of in the pipeline currently get completed. So that -- as we say, we're going to be completing 3 more wells this month. We have a couple more coming behind that in June. So getting into July, second half of the year, kind of feels right, in that we would have added enough. We think meaningful delineation wells to the mix, coupled with industry activity, that's really the key for us more so than what our specific rig count is at any point in time.

[Brian M. Corales:]

Okay. And the process, this isn't going to be a formal process or not just kind of cherry-picked handful of guys?

[Walter G. Goodrich:]

I think we'll run more of a full-blown process. It's a current thinking, Brian, and make sure that it gets fully vetted and our shareholders get the best value in transactions out there.

[Operator:]

Our next question comes from the line of John Freeman of Raymond James.

[John Freeman:]

I just want to follow up on the discussion on the pad development. So just to make sure that I understood properly. So initially, you'll have the smaller kind of 2 well pads kind of just in and around more kind of what I would consider kind of your core acreage around the Nunnery, Lewis, Bates area. And then, the more of the bigger, like the 4 well plus pads, is that something that we should assume happen in '15? Or is that even further off?

[Robert C. Turnham:]

No, I think -- John, this is Rob. I think '15 is more realistic. And we're not just going to be in Amite County doing some 2 well pads. For example, 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.

[John Freeman:]

So achieving the $11.5 million at year end on the well cost, that's assuming these pad wells?

[Robert C. Turnham:]

That is. That assumes a 2 well pad.

[John Freeman:]

Okay. And then, just one housekeeping item from me. Could you give me just ballpark how much of your acreage is in that Concordia block?

[Robert C. Turnham:]

That's about 40,000 acres. And we've seen potential activity levels from other operators moving west as we get through 2014. So we think that's a 2015 well that we probably drill. Could be as early as the end of '14, but likely a 2015 well. And we have plenty of time on those leases.

[Operator:]

Our next question comes from Pearce Hammond of Simmons & Company.

[Pearce W. Hammond:]

I just wanted to follow up on some of the earlier questions on the potential for a JV. I know when you acquired the Devon acreage, you ended up acquiring that relationship that Devon had essentially with Sinopec. So I was just curious, how does that play into your thought process? Could you expand that relationship? Or does it potentially complicate securing their JV? Or does it enhance it?

[Walter G. Goodrich:]

Yes, Pearce. This is Gil. I think, obviously, Sinopec's in control of what Sinopec wants to do. But given the relationship is in place, they will have an early, early look at the opportunity to expand the JV should they decide to do that. To a previous question, as I said, we're going to make sure, however, that our shareholders are getting the best value and the best structure that would be available. So I think they'll be in the mix. They're going to have a running start because they're going to have more knowledge about us as a company and our management structure, as well as the specific assets. And we've been sharing information with them across the play. So they're very knowledgeable. They're in a great position should they decide that, that's something they want to do. But ultimately, it's their decision.

[Operator:]

Our next question comes from the line of Kyle Rhodes of RBC.

[Kyle Rhodes:]

Just wondering if you could provide some color on your realized gas price. It looks like its differential to Henry Hub has gotten a bit wider over the last couple of quarters. And then you mentioned a lower borrowing base as a result of the bank's lower gas deck. I'm just wondering how we should think about that going forward, that differential.

[Robert C. Turnham:]

Yes, Kyle, this is Rob. I mean, obviously, getting -- it's a combination of a couple of things. Gathering expenses and fees primarily from non-operated properties are higher than some other previously reported gathering fees, and lower NGLs as a result of our Cotton Valley field in East Texas basically declining over time. And we typically take, well, -- we do take the uplift from NGLs in our gas price. And as that has dropped as a percentage of the total gas, then we have a little less uplift coming from the NGLs. So a bigger percentage of our gas now is coming from Haynesville and a bigger piece of the Haynesville is coming from Chesapeake-operated wells that we drilled at the end of last year, that's rolled into the first quarter. If you remember, we completed several wells in 2013 that had been previously drilled but not frac-ed and completed. The other gas component is in South Texas. That can fluctuate quite a bit, where we have different processing agreements. We recycle gas down there also, to using gas lift [ph], and so that can vary a good -- but I'd say those were primarily the components of what you saw.

[Kyle Rhodes:]

Okay. Does kind of going forward, first quarter kind of run rate to the rest of 2014 sound fair?

[Robert C. Turnham:]

I would say we should do better than that in the second half of this year once we complete our Angelina River Trend wells. The gathering fee down there is about $0.15 an M. It's dry gas, we don't get an NGL uplift. But certainly, that's going to enhance our realized pricing, but that's probably a third quarter -- beginning in the third quarter -- maybe end of third quarter likely, and more impactful in the fourth quarter. So I would just -- I would use that price realization for now and then perhaps start baking in the new volumes coming from the Angelina River Trend at a higher price. And that will allow that price realization to creep up.

[Kyle Rhodes:]

Perfect. And then just I know this is kind of jumping forward a little bit, but when you guys do go to kind of 4 well pad development in the TMS, what kind of spacing you guys kind of envisioning using there?

[Robert C. Turnham:]

Yes. This is Rob again. I think, initially, 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. But that makes some sense, space our wells out off of these pads based on that spacing between wells.

[Operator:]

Our next question comes from the line of Steve Berman of Canaccord.

[Stephen F. Berman:]

Rob, you may have just, at least, partially answered this with your Angelina River Trend comments. But just looking for when natural gas production might stabilize on a quarter-to-quarter basis and maybe even start going up again.

[Robert C. Turnham:]

Yes, I think it's really a late third quarter event. We're talking about spudding the Angelina River well 1st of July. It's probably a 75-day to 90-day cycle time there. So you're really looking at the vast majority of the benefit coming in the fourth quarter. And that, if we hit anything close to what the offset well has done, which is the EOG Sarge well -- we're not saying we will because that well is probably the best Haynesville well drilled to date. But obviously, because of our volumes over the years gradually coming down, that could be a very impactful well for us if successful. But I would just wait and kind of bake that in, in the fourth quarter. We really -- we could increase our activity level if gas prices continue to rise. But right now, that's the best guidance we can give you.

[Stephen F. Berman:]

All right. And that's the only operated gas well you have on the cards for the rest of this year?

[Robert C. Turnham:]

It is. We've given a range of activity in CapEx levels, which give us the ability of let's just say we have a really hot summer and we end the storage season at a much lower number we see better gas prices, we certainly wanted the flexibility of drilling more wells. And we've put that in kind of a range of budget. But I'd say we're going to spud 2 Angelina River Trend wells this year and complete 1. And that's where you get the kind of $25 million low end of the budget for that field.

[Stephen F. Berman:]

Okay. And one more, staying on the gas topic, any updated thoughts in this kind of $4.50 to $5 gas world we seem to be in now, possibly monetizing some of your gas assets here? I know you've done it before. What's your latest thinking there?

[Walter G. Goodrich:]

Steve, this is Gil. I'll tell you if the strip would start jumping up around $5, you'd see a significantly different posture from us both in terms of the divestitures and perhaps even reallocate some capital back towards gas. The problem, is we still have a significantly backward-dated strip out there. So as Rob said, I think -- we got some flexibility in the budget. We likely can move some capital around. In terms of divestitures, I think we're pretty content with watching how the refill season goes here for the next few months. We think there's at least a constructive story out there that says to get back to 3.4, 3.5, 3.6 Tcfs going to be a bit of a challenge. So we're happy to see that and watch how strip prices perform. Our Minden/Beckville Cotton Valley legacy field has always been, for the last year or so, a potential divestiture candidate. It remains in that status. But I think, we're, as a board, pretty happy to just see how gas prices play out here over the next few months and make a decision on that later this year.

[Operator:]

Your next question comes from the line of Ron Mills of Johnson Rice.

[Ronald E. Mills:]

As it relates to -- I think a follow-up on one of Brian's questions earlier, the addition of the fourth and/or fifth rigs. I know a couple of months ago, you had talked about taking a more conservative stance in evaluating both years in a couple of industry wells. Is it safe to assume now, with a little bit more consistency in terms of the last couple of wells and the way the next 3 wells have drilled, that you could be looking to add that fourth rig sooner than you may have thought during your February call?

[Walter G. Goodrich:]

Yes, Ron, this is Gil. I think you're hitting on exactly the right issues. We had a couple of good wells in a row here. We're obviously very pleased with that, and we do have 3 wells in the pipeline coming up in the month of May. So we don't intend to add a fourth rig per se during May. But with success there, and we get into June and July, then certainly everything's open in terms of the second half of the year. If we've begun a joint venture process and we're feeling pretty good about that, you certainly -- as you get around the middle of the year, you can see a fourth rig come in. We're going to kind of stay a little flexible, however, for the next 60 days and just see how these wells in the pipeline turn out.

[Ronald E. Mills:]

Okay. And then, as it relates to the Nunnery and the Blades wells, both of those were 6,000-foot laterals. It sounds like the plan is to use the incremental 100,000 pounds of proppant and also reduce those frac stages down to 250 feet. A, is that correct? And b, when you look at targeted drilling design, what do you -- what are you targeting probably going forward from a lateral standpoint?

[Robert C. Turnham:]

Yes. So a, yes, that is correct. Obviously, the Blades well, which has probably got a number of things contributing there, you certainly have to consider this little bit tighter spacing and more profit amount is an incremental contributor. I think if you look at what EOG and others have been doing here in terms of pushing the upper boundaries on proppant per stage or proppant per foot has led to increased results. So, we're in that camp and liking what we're seeing so far. So 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.

[Ronald E. Mills:]

And just on the proppant concentration, I know you had been in the mid-400s, and I know EnCana had tested had some higher concentrations. I don't know, maybe for Rob, what drove the decision to increase the proppant per stage on recent wells?

[Robert C. Turnham:]

Yes, just -- and Gil kind of hinted it to -- that the EOG and others, guys that are experimenting in other plays and productivity per linear foot as a result of a little bit more proppant. Now you can overdo it, pump too much water certainly and basically flood the zone, so we clearly don't want to do that. But we've only added a little bit of extra fluid to go with a little bit more proppant and tighten the intervals. And you can argue with the production per linear foot. It's our experience and its other operators' experiences in other fields that caused us to want to test that on the Blades well.

[Operator:]

Our next question comes from David Deckelbaum of KeyBanc.

[David Deckelbaum:]

I just had a question on -- when you look at the drilling times coming down by, in some cases, 16 days, 10 to 16 days, what's the biggest delta there? Is it just removing some of the -- some aspects of the well or what's -- is at the angle that you're using now going through the rubble zone? I guess, I'm just trying to understand how repeatedly you think the drilling day savings are?

[Walter G. Goodrich:]

Yes, David, this is Gil. I would say, generally, we're pretty confident that you'll see a gradual trend in the right direction in reducing drilling days. I don't think every single well is going to continue to get better than the previous one. They'll be -- it'll be a little bit lumpy. But a couple of kind of key areas would be building the initial part of the curve. In some areas, we've seen a little bit more difficulty getting that curve built than in other areas. And so that pulls back to bit selection for -- when you're going to build the curve, and then, how quickly you get your intermediate set and kicked off of that intermediate and finish building the curve. Those are the really the 2 key areas. Once we've overcome or if we continue to overcome the instability issue, the laterals have actually been drilling pretty fast here recently, both ours and others. And so by doing those things and eliminating the flat spots that you see, whether you're setting your surface or you're setting your intermediate strength, where you kind of sit there for a few days setting pipe, submitting it, the quicker you can turn that around, and that's a rig and crew issue. Those are things that we can narrow those and shave a few days off, then I think you'll ultimately see us, hopefully later this year with fairly consistent results under 40 days.

[David Deckelbaum:]

Great, that's helpful. I guess, as you think about the organization and going into the JV process, what do you think your sort of organizational capacity is in terms of the number of operated rigs?

[Robert C. Turnham:]

Yes. David, it's Rob. At the peak of gas prices in our Cotton Valley and Haynesville activity, we were running as many as 9 rigs. Certainly, we'll need to make sure our engineering staff is in order and fully staffed, fully capable of running 9 rigs with very little incremental G&A. The oilfield has the benefit of being able to use consultants in the field, so it's not all employee based. And we certainly have some good consultants that are helping us drill these wells. So we think we can run as many as 9 rigs with just not a whole lot of incremental G&A.

[David Deckelbaum:]

Sure. And lastly, I guess, as you think about success cases like what you've seen, you've talked with others about how you might scale up in terms of operated rigs throughout the rest of the year. If you get a JV partner and then things are moving swimmingly, I mean, how do you view Goodrich as a whole, considering the other assets that you have -- obviously, the Eagle Ford moves a lot of the value in the credit facility now, but if you have 8 rigs running in the TMS, you'd probably see that value pick up considerably as well. Longer term with -- and a success case here, would the Eagle Ford be sort of deemed a divestiture candidate as well or do you sort of view this as a fuller collection going forward?

[Walter G. Goodrich:]

Yes, Dave, this is Gil. I think, we obviously don't want to telegraph anything we may or may not do out in 2015, but you're hitting on at least an important subject for us, which is the success scenario here is where we're running 7, 8, 9 rigs next year is certainly going to be very, very capital intensive. And so we will need to be bringing in some incremental capital to help us do that. And therefore, we're going have to go through a very detailed rationalization of all of our assets to make sure that we were optimizing those and bringing the capital in the most efficiently with the least dissolution for our shareholders. I would only say kind of globally, while we may sell some gas assets, we don't intend, as a board, to get ourselves into the opposite position we were in a few years ago where we're 98% natural gas and 2% crude oil. We don't want to be 98% crude oil and 2% gas. We would, longer term, maintain some balance in the portfolio, so that if oil prices change in relationship to gas prices, we still got great flexibility with our capital.

[Operator:]

Our next question comes from Ben Wyatt of Stephens.

[Ben Wyatt:]

Just a couple questions for me on the TMS. One, you guys feeling in any acreage spots there or doing any swapping of acreage right now? Are those conversations happening yet?

[Robert C. Turnham:]

Yes, this is Rob. I think, we tend to have healthy discussions with all other operators in the area. If you can -- if we can swap out small whispering interest in some of their units for the same thing in some of our units, then that makes a lot of sense for us. So I think you'll continue to see that. That allows you to control your budget process much better and consolidate interest in the units in which you operate. So I think you'll -- yes, we've done some of that on a -- just on an immaterial acreage amount basis. And I think you'll continue see us do that. Doubtful you'd do it on a big swap of acreage, but certainly, the smaller working interest has made some sense to us.

[Ben Wyatt:]

Got you. And then, maybe just one more, staying in the TMS. Some of wells that you guys have had on production for quite a while now, obviously, holding up nicely against the type curve. Just curious what the products -- product mix looks like on those wells that they're -- coming online at 95% oil? How are those tracking and holding up as you move 6 months, 9 months, 1 year down the line?

[Walter G. Goodrich:]

Yes, Ben, this is Gil. We're still maintaining a fairly consistent gas oil ratio on those wells. So we're ranging from as low as maybe about 93% crude oil to as high as what we're seeing on the Blades, that's up around 95% crude oil. So predominantly, a crude oil stream, and to Steve's question earlier, we're not going to be having much gas volumes come out of the TMS.

[Operator:]

Your next question comes from the line of Mike Kelly of Global Hunter.

[Michael Kelly:]

Rob, you mentioned earlier that it's important to look at how these older EnCana wells have responded close to having their artificial lifts optimized. I was hoping you could maybe give a little more color on that. And I think it's Slide 19 in the new deck here that you can see them in these things look like they've bumped up a good 20% post that work. And it was really, I wanted to understand -- if you could break it down to a finance guy here exactly kind of what you did, and more importantly, probably, how you expect those rates to really hold up. Is this kind of a long-term effect or is this more -- what gives you confidence this isn't just kind of a short-term type boost, I guess, is my question?

[Robert C. Turnham:]

Yes. Mike, really once you go artificial lift, there's constant refinement, especially when you go on top. And in many cases, when you shoot fluid levels, you realize the pump's not working efficiently or effectively draining the lateral or draining the fluids out of the wellbore. And that's what it appeared to us on those 2 wells, that the fluid levels were higher than the pumped depth. And it wasn't efficiently operating so that you would -- what you want to do is produce what the well gives up. And in this case, the fluids were backing up into the wellbore and not unloading. So -- and we see that in Eagle Ford where you just have to constantly kind of tweak the parameters on the artificial lift so that you'd effectively and efficiently produce the wells. We're comfortable with our type curves. That puts those wells back on the type curves, and we think that we're going to see a real shot at those staying on the curves. If it were flush production, you'd see a good bit above even the 20% that you've mentioned that they improved, but it would come back down. So what we're saying, we'll just see over time. But what we're seeing is a flattening of those profiles, which is much more encouraging than something shooting up abnormally high or artificially high, and then, coming back down once you produce off the flush production.

[Operator:]

Our next question comes from the line of Joe Allman of JPMorgan.

[Joseph D. Allman:]

So Rob, you said that your target for drilling complete costs in the TMS is to get to $11.5 million by year end. So could you take us from your most recent well there? I think you said your Blades well cost under $13 million. Just take us from there and take us from the C.H. Lewis well and help us get to the $11.5 million.

[Robert C. Turnham:]

Yes, so I think the Blades well was 36 days. Obviously, that was kind of 9 days under AFE. So that's certainly helped on the cost. We really need to get those wells to 30 days ultimately. And you're going to have some that go really well, and you're going to have some that you have bits go out or something happens, and it's going to be a staggered approach and gradual over time. So I don't think you can just count on every well doing that. But we're targeting ultimately to drill these wells as low as 30 days. And I think that -- the closer you can get to that, the more cost savings you're going to see from drilling operations. 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. But we expect further reductions in all the other goods and services from there. The pad drilling is the easiest, frankly, because you're just getting a rig in 6 hours or 5 hours instead of moving it in 5 or 6 days. You're amortizing facility cost over 2 wells instead of 1. You're building one room. Some of that certainly is just a given. And then the zipper frac, we're utilizing the frac equipment much less time. We've estimated multi-well pads are 40% less time to frac the wells. Two well pads are probably going to be 25% less time, which means that equipment portion of your bid is going to be cheaper. So kind of a -- I can't walk you through the exact math on each $100,000 savings. But 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. Lateral length, the number of stages is kind of varied though. With the Lewis well -- and we're still experimenting if the 250-foot interval the absolute best. And certainly, you can't argue with Blades' result, but can you get the same result from 270 feet and more proppant? So we're experimenting with the frac intervals and perhaps 250 and a reduced amount of sand works off. These are all things that over the next 6 months we'll continue to experiment a little bit with. What we're not going to experiment with, though, are the material things that have created problems in the past such as permanent frac plugs and other items that created mechanical issues. So we're talking about just minor tweaks here.

[Joseph D. Allman:]

So Rob, I think, the Blades well, I think, you drilled that in 36 days, if I'm not mistaken. Is that right?

[Robert C. Turnham:]

Yes, that and the C.H. Lewis both were 36 days.

[Joseph D. Allman:]

And the Blades well, I think, was a 5,100-foot lateral and the Lewis -- C.H. Lewis well, the 6,600-foot lateral, if I'm not mistaken. Is that correct?

[Robert C. Turnham:]

It is exactly -- and Joe, we've seen another operator drill a well in 30 days. So we -- and the beauty of it, we won't -- we don't need to take credit for everything. We're happy to have someone else tweak it, and then, have that translate into better result. So with, yes, the thought of getting the 30 days like the other operator did, we think, is very feasible.

[Joseph D. Allman:]

But the C.H. Lewis well do you expect this to cost also under $13 million even though it's a longer lateral well?

[Walter G. Goodrich:]

Yes, it's close -- probably going to be closer to AFE. We need to get to frac cost at hand and drill out the plugs before we know. We certainly are in the ballpark of our AFE on that well. Even though it drills a little faster, we're using the Blades recipe in pumping the bigger design over 26 stages. So probably going to be closer through the AFE amount than being under.

[Joseph D. Allman:]

Great, okay. So just different topic. On EUR, I think, you mentioned that the CMR well, I think, your estimate is that it's running kind of along the 600,000 BOE type curve. And so the Blades is probably too early to tell, but how about the Crosby well? What's your best guess on what that EUR is going to be given your assumptions further up?

[Walter G. Goodrich:]

Yes, still running north of our 800,000-barrel curve. So we just need to continue to track it. I think that's 15.5 or 16 months now -- no, almost 15 months out, and you can see it still tracking above our 800,000-barrel curve.

[Operator:]

Our next question comes from the line of Jeff Grampp of Northland Capital Markets.

[Jeffrey Grampp:]

Just a couple kind of relatively quick ones. Curious on the infrastructure front in the TMS. How much of a constraint, if at all, that maybe in terms of ramping up activity in the TMS, assuming you guys continue to have success in the play there?

[Walter G. Goodrich:]

Yes, Jeff, this is Gil. Really no constraint whatsoever. We have 90-plus percent of the productions rate coming from black crude oil. We're trucking all of that to one of our couple of places very close by. And therefore, we're getting about $2 off of LLS. So we don't see any impediment from an infrastructure standpoint to that now. Obviously, longer term -- and we are stripping the liquids from the gas with portable units on locations. So we are capturing the NGLs out of the gas. Longer term, when we get to full-blown development and you start seeing central production facilities getting built in multiple well pads and some concentration of development, then, you're likely to see some buildout and be in position to look forward to invest in more of a gas infrastructure that could help us both move the gas to sales, as well as have a little bit more efficient manner of stripping the liquids. But that's probably -- minimum 2015, more likely 2016. So near term, it's hauling the oil off location by truck and stripping the liquids at location.

[Jeffrey Grampp:]

Okay. And then, last one for me, just kind of the housekeeping one. Could you guys provide us with what the net production was out of the TMS for the first quarter?

[Robert C. Turnham:]

It's running in the range of close to 20% -- 15% to 20% of total oil production.

[Operator:]

Our next question comes from the line of Ron Mills of Johnson Rice.

[Ronald E. Mills:]

Just from a frac or scheduling standpoint, given your activity increasing and the rest of the industry activity, any limitations in terms of availability of frac spreads, how many are running in the play and ability to manage the overall industry activity?

[Walter G. Goodrich:]

Ron, this is Gil. I -- we don't see any. In fact, we might argue that the opposite's the case, which is, with multiple operators out there and multiple activity, we're going to have more availability because the transportation piece could get eliminated and we can start sharing equipment that's already out there. But we believe there's plenty of capacity out there for what we need to do even going to 5 or 6 rigs.

[Ronald E. Mills:]

Okay. And then, I think the last rig that you added was a new build. Is some of the increase in drilling pace related to the new rigs? What are your thoughts as you either look to the -- adding your fourth rig or potentially swapping newer equipment for older equipment? Or how should we think about that?

[Walter G. Goodrich:]

Yes, well, so we just added a new rig, which has just drilled its first well. So we would not make any clear decisions about that. The 36-day wells that Robert referenced a minute ago we drilled with the Anderson rig that's been out there for a pretty good while. So that being said, yes, we are looking on a go-forward basis for the most efficient and that usually comes from the newer rigs, efficient rigs out there that we can help kind of reduce some of these flat spots and increase penetration as we talked about earlier.

[Operator:]

Our next question comes from the line of Adam France of 1492 Capital.

[Adam M. France:]

Two quick questions, Robert. Is there any interesting vertical well control around the Beech Grove or the Nunnery?

[Robert C. Turnham:]

Yes, Adam. What we love about the TMS is the abundance of vertical well control in the play. We have over 1,200 wells that have been drilled on its way down to see the lower Tuscaloosa. We put our Beech Grove well in between the Devon Beech Grove and the Devon Richland Farms. Even though it's a Southwest extension, we're directly in between those 2 wells. And that, obviously, gives us quite a bit of data points. We also just on -- just north and east of the Nunnery location is a vertical well with a very good resistivity curve that looks as good as any of the other wells. So that was a whole reason why we felt comfortable in taking that northeast extension because we have well data -- subsurface data just due east of that well. So any well that we drill, in fact, when you look at our map, you'll see it's safe, but you'll see a red dots throughout that whole map as shown on our TMS page at all of those wells penetrated the TMS. We have cross-sections throughout the entire area that tie not only a signature being the high resistivity curve and at least 100 feet of thickness and 5 ohms of resistivity or greater. But we also have plenty of wells that have actually flowed oil. Those are represented with red stars on the map. And so you can see, when you look at our acreage, not only do we have well control throughout the whole block, but we also wells that have actually flowed oil and that was key just to where we want put the block together.

[Adam M. France:]

Got you, got you. Robert, what, call it a debate, but what's left to decide in terms of well design as you've got -- you and the other operators are trying to cooperate and come up with best practices. What's left to debate?

[Robert C. Turnham:]

Yes, that's a really good question, Adam. You never say never. We certainly got some optimum completion recipe in the Haynesville and Eagle Ford, so you do get there. But to continue to refine it, I'd tell you we love having the other operators in the field. HK brings a lot of technical capabilities and savvy and work very well with those guys in particular, such as in EnCana 2. I think it gets there a lot quicker in the TMS that it did in the Haynesville and Eagle Ford, mainly because we're sharing data with everyone and everyone brings expertise to the table that might allow us to get the best practices quicker. So I don't know. We're doing minor tweaks now. We're not really doing major tweaks. We know you don't want to pump 100% slick water. The hybrid jobs seem to work better. You don't want to put too much fluid and too much sand. It's overkill. Frac intervals, we're just doing minor tweaking of frac intervals. So I think we're zeroing in on things much quicker than we did in previous play. The last -- and Gil can respond to, the last thing I -- question is just how low can we ultimately go on drilling. We think 30 days is very reasonable. But can you knock more days off of it than that if you go a little bit faster in certain of the slower areas? So I think that's just more -- but the good news is we've got the drilling issues behind us, with the rubble zone coming in at a steeper pitch and the completion seem to be pretty close to optimum.

[Operator:]

Our next question comes from the line of John Reardon of Merriman Capital.

[John Reardon:]

Besides the insignificant land swap that you alluded to earlier, have there been any recent dollar per acre land transactions in the TMS? And if not, would you care to venture a guess what a going rate per acre would be?

[Walter G. Goodrich:]

We're not familiar -- this is Gil. We're not familiar with any large significant transactions where there's a published number. I would say -- in my comments earlier, I talked about us at or very close to an inflection point. And I think that, really, where lands going to be as likely to start to get kind of settled out here in the next 6 months or so. So I really would have to say to venture a guess, other than to say that if you were going to buy a large significant block, it's certainly not in the few hundred dollar range. It's up into the thousand dollars of -- multiple thousands of dollars of range if you want a large meaningful position. And the fact of matter is, the big players that are in there that, including us, that have got the acreage, the large block tied up. I don't think any of us were interested in flipping out at that kind of number at this point. So where's the inflection point, I think the next 6 months are going to be very interesting.

[Operator:]

Our next question comes from the line of David Snow of Energy Equities.

[David Snow:]

Halcon had referred to possibly using snubbing units and club tubing to take out the plugs. And they also referred to, perhaps, lower frac pressures to prevent casing deformation or something like that. I'm wondering what you think of either of those? Do you think the snubbing units make sense? And do you think the lower frac pressures would lower your EURs?

[Walter G. Goodrich:]

Yes. -- no, yes, no we don't -- David, this is Gil. So yes, 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 lending 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. And so that's a little bit dependent on depth obviously. We've done that on the Blades. We did that on the CMR, which, obviously, had no diminishment of results. So I think, we got the right recipe regarding those issues.

[David Snow:]

Did you say there was somebody that did have problems on using snubbing units and coiled tubing?

[Walter G. Goodrich:]

Well, 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.

[David Snow:]

Okay, and do you think you could get to $10 million cost on a 5,000-foot lateral that tends to -- works best?

[Robert C. Turnham:]

Yes, David, this is Rob. Yes, obviously, the shorter the lateral, the fewer frac stages. You can drive your cost down. That's what was very interesting about the Blades. It does give you an example of a shorter lateral that has the potential of being a good bit cheaper if the production and EURs hold up similar to the longer laterals. Our experience in the Eagle Ford in particular, longer laterals, you may not see a one-per-one initial rate but you tend to see flatter curves because you have more feet in over time. But certainly, you have to factor in the fact that the shorter laterals are cheaper to drill, and ultimately, that could drive your decision process.

[David Snow:]

When you're targeting $10 million though you're looking for a longer lateral to apply to that?

[Robert C. Turnham:]

Well, 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.

[David Snow:]

And you think that basically the 5,000-foot didn't contribute tremendously to your bid successes in the recent well?

[Walter G. Goodrich:]

The 5,000-foot lateral on the Blades came in beautifully and couldn't be more excited about it. We just want to watch the production over 2 to 3 years just like we're doing on these other longer laterals. And we'll decide at that point if it's acting similarly to the long laterals. If so, we'd be crazy to not to drill them. The shorter laterals were cheaper, but we just need to watch the production overtime.

[Operator:]

I'd now like to turn the call over to Gil Goodrich for closing remarks.

[Walter G. Goodrich:]

Thank you, Rachel. Thank you, everyone, for your participation. We're very excited about the upcoming activity, particularly in the TMS. And we look forward to reporting that to you in early August.

[Operator:]

Thank you for joining today's conference. This concludes the presentation. You may now disconnect. Good day.