Goodrich Petroleum Corporation
Q4 2016 Earnings Call Transcript

Published: 2 Mar 2017

[Operator:]

Good day and welcome to the Goodrich Petroleum Fourth Quarter and Year-End 2016 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instruction]. Please note this event is being recorded.I would now like to turn the conference over to Gil Goodrich. Sir, please go ahead.

[Walter G. "Gil" Goodrich:]

Thank you, Dave, and good morning everyone. We are happy to be back with you on a conference call and reporting our financial results. As we standardly do, we want to warn you that some questions that we may give answers to and comments that we may make could be considered forward-looking statements and we have detailed those for you as risk factors in our SEC filings.Since the completion of our reorganization in October, we have been very busy strengthening our balance sheet and working to further improve and demonstrate the value and potential of our Haynesville Shale assets, and executing on our board approved strategy to resume growth and deliver value to all of our shareholders. We believe the press release we put out yesterday afternoon effectively illustrates each of these advances as well as path forward for Goodrich Petroleum.First, a dramatic evaluation in well and completion designs in the Haynesville has revolutionized the play and dramatically reduced breakeven costs, while expanding rates have returned. Recent, Haynesville activity both on and around our core acreage position provided significant proved reserve additions at year-end. In the year-end reserve report at SEC pricing, proved reserves grew to approximately 303 Bcf equivalent, with 94% of proved reserves being natural gas driven by the Haynesville proved undeveloped location additions.Deferred value at SEC pricing of $2.48 per Mcf and $57 per barrel was approximately $57 million. However, year-end proved reserves will run at $3 flat per Mcf would be $180 million and flat at $3.50 per Mcf, proved reserves would grow to approximately $260 million.During the fourth quarter of last year, we participated in two long lateral 10,000 foot Haynesville wells in the core area of the Haynesville in Caddo Parish, Louisiana. Both wells were completed with very proppant amounts of 4,200 and 5,200 pounds of profit per foot. As we previously reported, these two wells came online at a combined initial production rate of approximately 72 million cubic feet of gas per day.As we reported yesterday, the ROTC 1H well completed with 5,200 pounds per foot had an initial IP of approximately 40 million cubic feet of gas per day, and both wells have exhibited a very flat decline profile over the first couple of months. As a result, the two wells have produced approximately 4 Bcf of gas in a little over two months online.As Rob will review shortly, while it's still early in their productive life, these wells are trending above and in the case of ROTC 1, well above our 2.5 Bcf per 1,000-feet of lateral or 25 Bcf EUR type curve.As you will see from the fresh start accounting, fourth quarter DD&A was approximately $0.90 per Mcf equivalent. Again, while still early, we are projecting lower finding in development costs from our Haynesville development plans, and therefore expect DD&A rates to trend down slowly over time.As a result, recent well performance illustrates the path for our company to deliver exceptional production, developed reserve and asset value growth in the coming quarters and years. We have recently added an operated rig and our currently drilling our Wurtsbaugh 26H-1 in DeSoto Parish, Louisiana, which will be a 4,600 foot lateral with 5,000 pounds per foot of proppant.Following the Wurtsbaugh 26, we will drill the Wurtsbaugh 25 and 24H-1 with a plan 10,000 foot lateral in a high proppant amount. We expect to have working interest of approximately 75% in both of these wells with completions to occur during the second quarter of the year. In 2017, we announced the capital expenditure budget of $40 million to $50 million which will provide for the drilling and completion of approximately 9 to 13 gross wells or 3 to 5 net Haynesville wells in 2017.Finally and to highlight the potential impact of the long lateral high proppant and high volume Haynesville program, since the average net natural gas production rate in the fourth quarter of last year, we have seen net gas production grow by approximately 60% to approximately 24 million cubic feet of gas per day or 80% of the 30 million cubic feet equivalent which is our current production.With that, I'll turn it over to Rob, to walk you through our Haynesville play.

[Robert C. Turnham:]

Thanks, Gil. I would like to direct your attention now to the earnings slide which we had posted on our website, if you haven't already access the slide deck.Let's begin with Slide 5, our capitalization table. We had net debt of approximately $21 million at year-end, comprised of $37 million of cash, $17 million in the first lien term loan and approximately $41 million in second lien notes. The original principal amount of the second lien notes was $40 million, but we paid in kind or PIK the interest due in December with additional notes. We expect to continue to pick the interest in the near future which accrues at 13.5% per annum. The first lien term loan is LIBOR plus 5.50% and has a maturity date of September 30, 2019. The second lien notes mature six months after the first lien maturity date.Slide 6 shows our core properties where we retain approximately 48,000 gross, 24,000 net acres in the Haynesville, 215,000 gross, 156,000 net acres in the TMS and 32,000 gross, 14,000 net acres in the Eagle Ford. As Gil mentioned, as we sit here today our capital expenditure budget for the year and our focus will be in the Haynesville Shale in the core of North Louisiana were under SEC pricing we had 282 Bcfe of our 303 Bcfe of proved reserves reported at year-end again under SEC pricing.Slide 7 breaks out our 24,000 net acres prospected for the Haynesville, comprised of 16,000 net acres in the North Louisiana core and 8,000 net acres in the Angelina River Trend of the East Texas. Most of the attention has been our North Louisiana obviously and rightly so do the recent well results, but we would tell you that rock in the Angelina River Trend is similar, but the wells are deeper and more expensive, therefore our initial activity levels will remain in the core drilling between existing wellbores.As shown on Slide 8, the Haynesville has had over 2,700 wells drilled since the discovery in 2008, and we have participated in an 85 wells on our acreage. Averaging EUR from our 85 short lateral wells of 4,600-feet is approximately 5.4 Bcf from a very small fracs of approximately 1,100 pounds of proppant per foot. We are now drilling laterals up to 10,000-feet, and as Gil mentioned stimulation has increased to as much as 5,200 pounds per foot, yielding what we believe to be in excess of 2.5 Bcf per 1,000 feet of lateral.One of the advantages of the Haynesville over other prolific gas basins is net price realization in which our gathering contracts and bases differentials provide on average about $0.60 per Mcf off of Henry Hub. With our operated net backs as low as $0.37 off of Henry Hub, so very good price realizations compared to other prolific basins.Many of you likely know the geologic characteristics that make the Haynesville a world class natural gas basin as shown on the Slide 9, but the 250 feet of average thickness combined with log porosity readings of up to 15% or greater and the brittleness of the rock are yielded an exceptional results when the proper completion technique is applied.On Slide 10, we show a cross section of the Haynesville from East Texas to the West to the eastern edge of the play in North Louisiana. What you'll see is the zone thickens and the porosity improves as you get to our acreage in North Louisiana. The same holds true when looking at a south to north cross section as found on Slide 10. Starting at our Angelina River Trend acreage in East Texas through our Bethany-Longstreet acreage in Desoto and Caddo Parish, Louisiana, through our Greenwood-Waskom area of Caddo Parish. The quality of this section of our acreage is very consistent and in the Angelina River Trend acreage we have very good Bossier Shale play developed as well.On Slide 12 and 13, we show isopachs of the Haynesville, whereby we map the thickness of the internal that has a minimum of 8% to 12% porosity on those two maps. Both slide show that we have a very thick column of Haynesville Shale with a minimum of 8% to 12% porosity.As you likely know, and as we shown on Slide 14, our industry has gone through an evolution on the completion side that is transformational for certain fields including the Haynesville. Over time, our industry and we have lengthened the laterals, shortened the frac intervals, tightened the cluster spacing and increased the proppant and corresponding water per foot of completion. In the Haynesville we are experimenting with 100 to 200 foot frac intervals in our latest well results are indicative we think of zeroing in on optimum completion techniques.The evolution is further documented on Slides 15 and 16 whereby we plot different operators, the evolution of lateral length and proppant concentrations over time, as well as stage interval lengths. When you run a linear progression of proppant concentration versus results, there is a very strong correlation when drilling in similar areas and the slides toward the end of our deck show that are in our opinion.Our activity map on Slide 17 is busy, but we think very informative. The old grey lines on the map are short lateral wells drilled prior to 2014. Recent short lateral wells are shown in green drilled post-2014, recent 7,500 foot laterals are shown in yellow or orange and recent 10,000 foot laterals are shown in red.Our acreage is in yellow and as you can see there is been quite a few recent wells drilled on and around our acreage with more to come. Our 2 ROTC wells that Gil referenced before are on the northern end of our Bethany-Longstreet block with quite a few well surrounding us to the south. Comstock a company that is posted very good well results in the play as recently permitted a number of wells offsetting our acreage at Greenwood-Waskom on which we feel very good about as well.Beginning on Slide 18, we show our two type curves for 46,000 foot, 75,000 foot and 10,000 foot laterals. Our curves are based off of well results over the last year or so that were supporting 2 to 2.5 Bcf per 1,000 feet of lateral. The more recent wells that have higher proppant concentrations are actually well above our high case curve and 2.5 Bcf per 1,000 feet of lateral.On slide 18, we focused on 4,600 foot laterals that pumped a minimum of 2,700 pounds of proppant per 1,000 foot of lateral to a maximum of 4,700 pounds per 1,000 feet of lateral. The wells that pumped 2,700 pounds per 1,000 feet are riding our 2.5 Bcf per 1,000 foot curve. While the 3,600 pounds per 1,000 feet and certainly the 4700 pounds per 1,000 feet of lateral are far exceeding our high case curve.On Slide 19, where we focus on 7,500-foot laterals to correlation of proppant per foot to results continues with wells with 2,800 pounds per 1,000 feet performing on or above our 2.0 Bcf per 1,000 foot curve to the wells that have pumped 3,600 pounds per 1,000 foot riding well above our high case curve. There are three exceptional wells on this slide, whereby the operator pumped only 1,500 to 1,900 pound per foot and these wells are adjacent to our block at Bethany-Longstreet.There are far fewer data points to look at on Slide 20, which is the 10,000 foot lateral curves, but it is no secret that Chesapeake is completed some recent wells, two of which were ROTC wells well above our high case curve. Even the lower proppant 10,000-foot wells adjacent to our acreage that were drilled with 10,000 foot laterals are performing exceptionally well. As we stated earlier and in the press release, the 2 ROTC wells have produced in excess of 4 Bcf in a little over two months and are still flowing in approximately 61 million cubic feet per day.We believe in pressure maintenance as does our operator on those two wells when flooring our wells, whereby you limit the drawdown per day to a minimum amount in this case 30 to 50 pounds per day, which we feel like it is optimum for producing the wells. The wells have flatter curves that are supported both in rate and in pressure, and it's going to be best for the wells in the long haul.As we sit here today, we are gridding six wells per unit, space at 850-feet between wells which is supported by ROTC spacing at approximately 900-feet apart. It certainly is possible to reduce the spacing to 660 feet between wellbores, which would generate 8 wells per unit by staggering the laterals both high and low, but our current preference is to land low in the hot gamma signatures which we believe is indicative of better quality rock.Our economic analysis slide beginning with Slide 22 we believe are compelling. When you bake in our 2.5 Bcf per 1,000 foot curve even though many wells are trading well above – are producing well above that. Based on proppant concentration and well costs for 4000 pounds per 1,000 per foot of profit. We see rate of rates of return from 53% on short laterals, 60% on 7500 foot laterals, and 76% on 10,000 foot laterals when plugging in $3 gas prices. These odd economics are run with current service cost estimates which are certainly higher than they were some time ago, so there we feel like are very, very prompt in current economic analysis for these wells.Just a reminder, the State of Louisiana has severance tax abatement and feel the early year of payout or two years, the Haynesville wells have very low lease operating expenses as low as $0.05 per Mcf equivalent initially and our net backs are very good compared to other prolific natural gas basis.With that I will turn the call back to Gil Goodrich for closing remarks.

[Walter G. "Gil" Goodrich:]

Thank you. I think that the presentation Rob just walk you through a pretty well illustrates why we're very excited about where we're positioned. And with the Haynesville assets we hold provides exceptional growth opportunities and an extraordinary rate of growth story.And with that operator, we'll turn it back over to Q&A.

[Operator:]

Thank you. We will now begin the question-and-answer session. [Operator Instruction] And the first question comes from John White with ROTH Capital. Please go ahead.

[John White:]

Good morning gentlemen, and congratulations on a nice operations press release.

[Walter G. "Gil" Goodrich:]

Thank you, John.

[John White:]

I was very encouraged to see your report current production of 30 million Mcfe per day because as you know my first quarter 2017 projections are about 25.9 million cubic feet a day. So we're glad to see that line up as it did and congratulations on the reserves also of 450%increase over 2015. Really shows what's happened with this play and all really reflective of all the offset drilling activity. I spent some time on your new Slide 17 recent completions and I noted you'd added your Wurtsbaugh well, and Gil commented that well is drilling. May be I missed it, but what's the timing on completing the first Wurtsbaugh?

[Walter G. "Gil" Goodrich:]

Yeah. This is Gil. So, we currently expect to finish this well up probably pretty quickly here in the next few days and then we'll move that rig over and drill the second Wurtsbaugh which will be a 10,000-foot lateral. John that should take roughly another 30 days we so we ought to be moving that rig out. So call it around April 1 – early April and we're looking at frac dates now that are probably going to be best guess today would be late April, very early May, with hopes to be able to frac both those wells back to back.

[John White:]

Okay. That's helpful. And you also have a well slotted on Slide 17, the W Franks?

[Walter G. "Gil" Goodrich:]

Yes. That really is an alternate well. John, we can re-flexibility to drill either the Franks or the Wurtsbaugh 25 and 24. So there is actually two locations for that particular unit. A few months ago, we thought we probably we're going to go to the Franks location and now currently thought we're going to Wurtsbaugh 25-24. So they're really right next to each other very similar wells.

[Robert C. Turnham:]

John, this is Rob. As we sit here today, we likely drilled both of those wells during 2017, but as Gil said, looks likely the Wurtsbaugh first.

[John White:]

Okay. And it looks like there is been quite a bit of activity as I compared your slide from yesterday to your December presentation and it looks like you've added a Chesapeake, set a wells named PE 36 & 25-15-15?

[Walter G. "Gil" Goodrich:]

That's right. So what we've really done on this map is just updated for data when it comes in, whether it's on the schedule would be drilled on not. For example, you know you have to get out ahead on your permitting for regulatory purposes when drilling these cross unit laterals. And as those permits or notifications become obvious, we're spotting them on the well. So 2017 budgets a bit fluid, we think as we sit here right now that we could operate as much as two-thirds of our activity in 2017 with probably a mirror image of that in 2018 where we expect Chesapeake to get even more busy on our acreage based on input from them.

[John White:]

Okay. I appreciate that also. And do you foresee or are you planning any 2017 wells of that Greenwood-Waskom?

[Robert C. Turnham:]

No. The good news is as Comstock, you know who are very close with has notified everybody they can now move a rig in in April to drill offsetting us at Greenwood Waskom/Metcalf, and our plan is currently are to start developing or drilling wells out there in 2018. So, we'll concentrate all of our efforts at least as we sit here right now at Bethany-Longstreet for 2017.

[John White:]

Okay. Well, if there is somebody else in the queue, I'll stop there and look forward to seeing you in a week or two at our conference.

[Walter G. "Gil" Goodrich:]

Thank you, John.

[Operator:]

The next question comes from David Baird with Coker Palmer. Please go ahead.

[David Baird:]

Good morning gentlemen, and also like to add John's congratulations on the results.

[Walter G. "Gil" Goodrich:]

Good morning, David. Thank you.

[Robert C. Turnham:]

Thank you, David.

[David Baird:]

I think that's a micro and macro questions, we'll start with on the micro on the completion side. Would it be fair to assume you would move to the W Franks after finishing up the second Wurtsbaugh or still up in the air?

[Walter G. "Gil" Goodrich:]

Yes. So David, this is Gil. Current plan is that we would be releasing that Nabors rig after we finish the Wurtsbaugh. And as Rob said, we have plans to come back firmly into the third quarter, be best-guess today to more than likely drill that Frank's location.

[David Baird:]

Okay. And then relative to your completion design, you know the Wurtsbaugh 2 and the Franks, so they're going to be 5,000 pounds or are you still debating the track designs for those two?

[Walter G. "Gil" Goodrich:]

Well, this is Gil again. I would say that we're certainly watching everything almost every day that we get new information and what we see today is that 5,000 pounds as Rob showed with the presentation is leading to better and better results. There is a cost versus results equation that we're looking at very carefully. And we certainly on this first Wurtsbaugh that we are drilling now, our current plan is to pumped 5,000 pounds per foot. And on the second one I think we'll leave it open to see exactly where we are at that moment in time, but certainly planned to pump either 4,000 or 5,000 pounds per foot.

[David Baird:]

And that does lead to my second question just about pricing, what have you guys assume for these 10,000-footers in terms of cost. Could you just comment on the sand pricing and if you're using no, then why there, just looked at the option of bringing in some Mississippi brown [ph]?

[Robert C. Turnham:]

Yes. So as to the cost, we are projecting about $12.5 million for a 10,000-foot lateral or the 4,000 pound per foot. That can vary. One of the other things that we're monitoring very closely is frac interval length. We're not totally convinced, you have to go all the way down to a 100-foot stage length verses if you look in the slide deck in particular look at the chart that shows various operators in the frac stage links and you'll see a large number of really good wells with 200 foot frac stage lengths. And our initial well we're going to – that we're operating right now, the Wurtsbaugh, we're going to do it on 150-foot intervals.And obviously if you can hit in between on 150-foot interval verses 100 saves you about a third of your number of stages and at $100,000 a stage that's obviously a significant cost saving. So, as we sit here right now, this is our best guess at about $12.5 million on the 10,000 foot lateral.As to sand, we're pumping Northern white currently. We had completed a number of wells in the TMS using regional brown sand and have made very good wells with the brown sand. We usually buy our sand. Actually, we basically buy everything associated with the frac through the provider. We're not logistically set up to buy this sand and deliver the sand to the location. So, as long as we get competitive pricing from the pressure pumping firms, were likely to bundle those services. We do continue to monitor that however and if there becomes a dislocation, then we certainly can do that in the future.

[David Baird:]

All right. Good. And the last question is a little bigger question given all of the activity in the basin and potential IPOs. Can you just comment about M&A an acre prices in the Haynesville and also touch based on the TMS given the Encana transaction that I think on Monday.

[Walter G. "Gil" Goodrich:]

Yeah. David, this is Gil. I'll take the first half of that. M&A we think is – you've seen obviously a couple of deals here at Chesapeake divest themselves of kind of their northeastern block, which went to Covey Park, and then the southwestern block which went to Indigo Minerals. The Haynesville is a relatively small, particularly Northwest Louisiana Haynesville, relatively small footprint, dominated by a handful of players. And so, we don't really see coming down the pipe any or in the near future, any large M&A transactions. We do see some smaller bolt-on opportunities. We are evaluating a few of those and we certainly hope in the coming months or quarters that we're bolstering our land position. Maybe in a modest way, but to smaller type transactions we're looking at that today.As for the TMS, boy, we would love to been in a position to be able to competitive in that. It looks to us like the entire Encana position went for something, at or less than PDP value, so picking up the acreage for very little. But the reality is that in our view that play work – starts to work in terms of new development at $65 to $70 a barrel. We currently have our handfuls here with Haynesville and delivering what we believe we're going to be ordinary rates of return.So, very difficult for us to see allocating capital borrowing some sort of an outside transaction that would help us further develop that.

[Robert C. Turnham:]

And David, let me add one thing. The largest frac job we ever pumped in the TMS was 2200 pounds per foot and it was done on a 5,000 foot lateral. There are no questions in our mind, it appears to be the best or it's not one of the best results per foot in the TMS of all the wells that have been drilled. So, it's just screaming for better completion recipes in the CMS which is going to yield a lot better results we think in the future. But for us, as Gil said, allocation of our – capital allocation of our budget, it's going to have to generate much better rates of return to get a portion of our capital expenditure budget.

[David Baird:]

Great, understood. Thanks for the time gentlemen.

[Walter G. "Gil" Goodrich:]

Thank you.

[Robert C. Turnham:]

Thanks David.

[Operator:]

The next question comes from Jeff Grampp of Northland Capital Markets. Please go ahead.

[Jeff Grampp:]

Good morning, guys.

[Walter G. "Gil" Goodrich:]

Good morning, Jeff.

[Jeff Grampp:]

Question on – and you guys kind of highlight the various economics across just the different lateral length and even on short one looks pretty compelling. Can you guys kind of talk that how we should think about kind of the mix of the various laterals in your development program going forward?

[Robert C. Turnham:]

Yeah. Great question. Really in 2017, the only short lateral we are expecting to drill is the one we're drilling right now. It's a location that was islandised. It had a well north of it and the well south of it previously drilled. So, in our opinion, it kind of gave us the ability to move and we knew we'd have a high working interest drilled the short lateral, put the really big 5,000 pound per foot frac on it. Ease into our drilling, knock the rust off of some of our drilling again, and be well positioned to then execute really well our 10,000-foot lateral that's going to follow it up.So I think, as you look right now just I would – our plan is to drill 10,000-foot lateral for the remainder of the year unless well proposal comes on the desk from either Chesapeake or someone else that we evaluate and decide to participate, and that's a 7,500. So I think that's the plan for 2017. If you look at our inventory in general, we're probably looking at about half our gross 235 gross locations being 10,000-foot laterals and the other half being split between 4,600s and 7,500s.That being said, the likelihood is that we don't drill that many 4,600s, so we're talking to offset operators about either acreage swaps of joint wells or participation in joint wells, so I think that's a likelihood that in the future, you will see us drilling far fewer, very few 4,600-foot laterals over the block.

[Jeff Grampp:]

And back on the M&A thought process, should we expect you know you guys to be more involved in kind of bolt-ons in the Haynesville? Is that kind of where any of your M&A focus would be, or would you guys love to potentially expand further in Eagle Ford or any other basins that might you know keep your interest of opportunities?

[Walter G. "Gil" Goodrich:]

This is Gil, and I can just say that near-term, which is certainly 2017 and likely 2018, we're going to be really focused just on Haynesville and all of our efforts today in terms of smaller bolt-on opportunities that we're looking at would be in the Haynesville and all those frankly would be in the core of Northwest Louisiana Haynesville.We like the Angelina River Trend, we see some things going on there. It's possible we could use some transactions down there. We do have the VP as we have a couple of Haynesville wells. It's currently drilling a third one, and has had talk of maybe doing a Bossier test down there. So, we'll just kind of sit back and see how that plays out over time, but right now the focus is on the Haynesville.

[Jeff Grampp:]

Okay. And last one from me and I apologize if you guys covered this in more detail in the prepared remarks. As far as the uplifting, can you guys just comment a little bit about expected timing and any kind of remaining hurdles, addressal that you guys need to have to accomplish that?

[Robert C. Turnham:]

So, where we – we're filing our 10-K, we think by the end of the day tomorrow. We're likely filing our application to New York Stock exchange early next week. We've already had preliminary phone calls with them. That process we've been told, takes 45 to 60 days. They've reserved our old ticker, GDP, so that's very positive and we meet all the requirements that they show in their listing materials and they've already opined, they are subject to review of the financials that they think we certainly meet those credentials as well. So that's the game plan on the uplifting.

[Jeff Grampp:]

Alright. Perfect looking, forward to it guys. Thanks for the time.

[Operator:]

The next question comes from Dylan Leith with Shenkman. Please go ahead.

[Chris Gault:]

Hey guys good morning, this is Chris Gault. One of the questions I think have been answered here, but just as with regards to 2017, we got know that you guys said that production will be double the rate of 2017 or 2016 and 2017. Can you give any thoughts or clarity on just kind of how that may look as we go through the quarters, through the year? It could be pretty lumpy and moving around, or, is there any kind of color you can kind of give there as of good increasing moves increases?

[Robert C. Turnham:]

Chris, this is Rob, so it can't help, but be a little lumpy when you look at just the sheer volumes that come from these wells. So, you know timing of completions is going to create spikes in production. So, just take for example a starting point of 30 million a day as we sit here, you know kind of right now. If we get these two wells completed, you know late April, 1st of May and they come on anywhere close to what we've seen before, with a blended average net revenue interest of 50% to maybe a little bit more than 50%, you can see the surge in volumes is pretty dramatic.So, it's all going to be dependent on timing of wells and timing of frac dates and that sort of thing, but clearly, you could see a huge surge in gas production from us before June 1, that's going to be certainly, the potential for more than double where we are even where we sit right now with $24 million a day. So, it's going to be and then you got to manage your declines from there until you get your next well completed. So, I think a bit lumpy until we get this thing smoothed out, and we get the base higher, because as you know the story is just a rate of change story for the Company and dramatic growth in both production and cash flow.

[Chris Gault:]

Sure. Okay, that makes sense. And then for some of these other cost items, in production taxes during the quarter, I guess we're less than 2%. I know you all said that you have this abatement period and all that. Is that kind of what I would expect uncertainty that fourth quarter rates are going to be pretty consistent for what I should expect for 2017?

[Robert C. Turnham:]

Yeah, this is Rob again. So, think about the volumes, in particular if you are looking at per unit metrics, and you just think about the sheer volumes coming in at zero production tax and so both the per unit cost are going to continue to just drop like a rock if you can double your production with zero production tax. As to older wells that as passed either payout or the term, obviously those production volumes are going to continue to fall and so less and less production coming from wells that are actually paying severance tax. So, I think we can probably at some point tighten the guidance a little bit I think just directionally. That's something we would point to that – it should fall pretty aggressively over the year.

[Chris Gault:]

And the cash G&A, the 2.6 you all did in the quarter, is that reasonable estimate of kind of going forward?

[Walter G. "Gil" Goodrich:]

This is Gill, maybe a little bit high Chris, but for modeling purposes, I think you are fine with that. It maybe touch high. Obviously from year-end associated G&A cash cost that we wouldn't expect to see quite as much in the second, third and fourth.

[Robert C. Turnham:]

Yeah and it's actually, you know it was $2.2 million from October 13 through December 31 and actually cash G&A was $2 million, so that's you know – let's call it 75 to 80 days of the 90-day quarter. So, we would expect that cash G&A to be less as Gill said, than what you quoted.

[Chris Gault:]

Okay, great. And then for hedging, your [indiscernible] one color works 2017, is that limited by what you will see in the market? Or is that limited just by the bank group and when can we expect I guess to see more hedges wired in, and what's your strategic going forward I guess?

[Walter G. "Gil" Goodrich:]

Chris, it's Gill

[Chris Gault:]

So it's not the bank group, but literally you are waiting for a better time period?

[Walter G. "Gil" Goodrich:]

Yeah. We're just trying to be a little bit patient here to pick our points as a committee.

[Chris Gault:]

Okay, and then my final question. Can you disclose what the PV-10 was for the TMS assets, is that something you all have handy?

[Robert C. Turnham:]

Chris, we're in Dallas at an event and don't have those slides in front of me. It's obviously all PDP, but we have no [multiple speakers] developed. But I can get that to you at a later date, and I think it will be – it may be shown on the 10-K also which we had sent to file by the end of tomorrow.

[Walter G. "Gil" Goodrich:]

It should be.

[Chris Gault:]

Okay. Alright. Great. Thank you

[Robert C. Turnham:]

Thank you.

[Walter G. "Gil" Goodrich:]

Thanks Chris.OperatorThe next question comes from Diana Gabricelli, Merrill Lynch.

[Diana Gabricelli:]

I'm a stockholder and I had received information that you were filing for bankruptcy, but now restructured and not, how does that affect the stockholders now. I have not sold or gotten rid of any of the stocks.

[Robert C. Turnham:]

Yeah. So, those shares were actually cancelled as a part of the bankruptcy. There is an abundance of documentation and disclosure that refers back to the old shares. So, unfortunately, once the filing occurred, you know the second lien holders became the fulcrum security and drove the process, and at the end of the existing or the old common holders did not get any of the new equity. So, that's all of that stock has been cancelled.

[Diana Gabricelli:]

Okay, because I did not receive any notification, and I was waiting for that.

[Walter G. "Gil" Goodrich:]

You should have this Gil Goodrich. You should have. We put out and disseminated information to all of our common holders as well as all of the bondholder in our cat structure, so very surprising, if you were a holder of record that you didn't get a notice, and not just a notice, but lots of documentation.

[Operator:]

The next question is a follow-up from John White with ROTH Capital. Please go ahead.

[John White:]

So, you've got your senior bank term loan when you've got plenty of time on that in terms of maturity, but have you been in discussions as to a revolving credit facility?

[Walter G. "Gil" Goodrich:]

So, John, this is Gill, we certainly are thinking about that and I think that at appropriate time that makes a lot of sense. Obviously, just coming out of reorganization, the trailing EBITDA numbers are still fairly weak given most of that period of time, we're still pre or in bankruptcy. We think another quarter or two down the road, when we start to see the EBITDA and the trailing EBITDA number start to improve, which we think they are going to improve quite dramatically in a couple of quarter, probably feels like a little bit better time to go about that effort. But we are open to it and we certainly think if this unfolds, you will see us replace that and put a new RB on place.

[John White:]

I appreciate that additional detail. Thank you.

[Operator:]

And this concludes our question and answer session. I would now like to turn the conference back over to Gil Goodrich for any closing remarks.

[Walter G. "Gil" Goodrich:]

Sure. Thank you everyone. We appreciate your time and listening to us and asking questions this morning. Very excited about where we are and we look forward to reporting operating results till you hear in the coming months. Thank you.

[Operator:]

The conference has now concluded Thank you for attending today's presentation. You may now disconnect.