Goodrich Petroleum Corporation
Q4 2017 Earnings Call Transcript

Published: 1 Mar 2018

[Operator:]

Good morning and welcome to the Goodrich Petroleum Year-End 2017 Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there'll be an opportunity to ask questions. [Operator Instructions] Please also note that today's event is being recorded. I would now like to turn the conference over to Gil Goodrich, Chairman and CEO. Please go ahead.

[Gil Goodrich:]

Thank you, Anita, and good morning everyone. Thank you for joining us. This morning, I am pleased to have an opportunity to share with you our full-year and fourth quarter results as well as a few exciting recent developments. We prepared a slide presentation in conjunction with the call this morning. And we invite you to follow slide deck during our prepared remarks. You can access the slide presentation on our Web site entitled Earnings Call Slides Year-End 2017. Our standard disclaimer, forward-looking statements and risk factors are highlighted for you on slide two. Before reviewing the quarterly and operational results and for those of you who maybe new to the Goodrich story, I would like to begin with slide three which provides an overview of the company as well as provides details regarding our plans and guidance for 2018. While we retain oil focused assets in the Eagle Ford Shale and TMS, our focus is on the new Haynesville Shale play in Northwest Louisiana, where longer laterals, tighter frac interval spacing and higher profit amounts have completely revolutionized the play. Our current Northwest Louisiana, Haynesville position contains a 15-plus year inventory of drilling locations at our 2018 rate of development and in excess of 1 Tcf of net reserve exposure, all of which has been extensively delineated by industry development over the past 10 years. Our company's common stock is traded under the symbol GDP on the NYSE American where we had the privilege to ring the opening bell two weeks ago this morning, just in case any of you missed us. In 2018, we believe you will find a company offering shareholders exposure to very rapid production volume and EBITDA growth while maintaining very low and conservative debt metrics. This opportunity is provided by the new Haynesville Shale, which as I mentioned has been transformed by new completion methodology. As an example of the new completion methodology results, this morning we announced two additional 7500 foot operated Haynesville wells recently completed and added to production, with a combined initial rate of 55 million cubic feet of gas per day. In addition, this morning, we announced the sale of a portion of our East Texas Angelina River Trend assets, with a portion of the proceeds used initially to pay off our first lien revolver of $16.7 million and for acceleration of our capital expenditure plans in the second half of 2018. We are subject to a confidentiality agreement with the purchaser, which is BP. So, details of the transaction in our prepared remarks will be limited. Our current 2018 capital budget calls for approximately $70 million of CapEx at the midpoint, which is earmarked to drill approximately 16 gross or 6.5 net wells in the Northwest Louisiana, Haynesville with a blended average lateral length of approximately 9000 feet. In addition, the asset sale announced this morning will allow us to accelerate development in the second half of the year with the exact timing, location of wells and magnitude of the capital increase to be determined over the next several weeks. And we will communicate those to you at the appropriate time. We are maintaining our production guidance for 2018 of an average of 77 to 83 million cubic feet of gas per day until we quantify the acceleration program in the second half of the year. Because the nature of the wells we are drilling are very high volume wells with significant working and net revenue interest, the ultimate timing of activity and completions will play a role in both quarterly and full-year reported volumes. However, with a significant portion of our cost structure relatively fixed and the incremental operating expenses from new wells not materially adding to our cost structure, we are projecting substantial margin expansion and EBITDA growth associated with the production volume growth we anticipate for 2018. If you will now turn to slide four, I will review some quarterly and full-year highlights and recent developments. During the fourth quarter, we incurred capital expenditures of $16 million and $41.8 million for the full-year 2017. And we were not able to start frac operations on the three recently-completed wells until mid-December. We do not add any new wells to production during the fourth quarter and produced an average of 31.2 million cubic feet of gas per day for the quarter, which was affected by the delays and the shut in of all set production during frac operations. Absolute volume levels and associated EBITDA for the fourth quarter were impacted versus our previously expected timing of completions, primarily as a result of several third-party service company like as well as the shutting in of all near offset wells in order to ensure maximum quality in new well stimulation during frac ops. However, the timing delays had no impact on the quality of the new wells with all three wells operated recently added to production coming in a combined growth initial production rate of 65 - excuse me 85 million cubic feet of gas per day. With the addition of the three new wells, which are being produced under a restricted choke and pressure maintenance problem, our current net production is approximately 60 million cubic feet of gas per day. Continuing the production volume growth, looking forward, we have two additional Haynesville 10,000-foot laterals in which we hold a 92% working interest scheduled to be frac in the first half of March with production from these wells anticipated in April. While we may be a bit behind for the first month or so of this year, recent wells are performing at or above expectation and we are on pace to deliver strong production growth in 2018 with plans for acceleration to be outland as I said in coming weeks. During the fourth quarter, we reported adjusted EBITDA of $4.4 million, again which was impacted versus prior expectations by the previously mentioned delays. However, given our current run rate and high work into interest wells to be added near the end of the first quarter, we are forecasting very robust EBITDA growth in the coming quarters. The balance sheet remains in excellent condition and provides up the opportunity to both expand our liquidity and accelerate growth during 2018. As we entered the year with 26 million of cash on the balance sheet and total and therefore total net debt of $37.7 million. If we perform on today's asset sale into the year in numbers, net debt would drop to just $15 million. As stated earlier, we planned initial use a portion of the proceeds from the asset sale to pay off the approximately $16.7 million currently outstanding under our revolver. In addition, we have delivered our bank group, our year-end 2017 reserve report, we will do so again with a midyear reserve report at the end of June and our expectation given our production EBITDA and developed reserve growth forecast is for an increasing volume base amount available to us an increase in overall liquidity in 2018. Turning to slide five, you will see a chart showing our year-end 2017 SEC proved reserves and the reserve growth of the past couple of years. Proved reserves grew by over 40% to 428 bcf equivalent in 2018 versus year-end 2016 consistent with our focus of development activities all reserve growth associated with our Haynesville Shale assets in northwest Louisiana. SEC reserves remain a subset of our total northwest Louisiana reserve exposure and we expect continued reserve growth and conversion of reserves in the proved developed over the course of 2018. Moving to slide six, you will find our cap table as of the end of 2017 as I mentioned we ended the year with $26 million in cash. We have $16.7 million outstanding under our revolver and $47 million of secondly convertible notes with a pick option, which we have extras with respect to interest payments thus far. This is a very simple balance sheet and results in $63.7 million of total debt, 37.7 of net debt and as I said with a performance of days asset sale and we would have just 15 million of net debt after the asset sale. On slide seven, you will see a chart showing our net production volumes. The quarterly growth in volumes during 2017 as well as the aforementioned impacted of the timing delays and shut-in in the fourth quarter of last year. Most importantly, the chart illustrates our current run rate and our projected average daily rate at the midpoint of guidance for 2018. And with that, I'll turn it over to Rob for some trading analysis and additional activity update.

[Rob Turnham:]

Thanks, Gil. As Gil mentioned earlier, with the recent completions is driving at current production rate of approximately 60 million cubic feet equivalent per day, as well as the next two high working interest 10,000-foot wells getting fracked in March, our numbers will be changing dramatically over the next few quarters which will drive EBITDA growth. Looking at the fourth quarter and full-year 2017, our revenues for the quarter and year were $11.1 million and $46.2 million respectively. From an average realized price of approximately $3.78 per Mcfe for both periods prior to benefit of our hedge book. Our hedge is added approximately $0.06 per Mcfe for the quarter to our realized price on a per unit basis. For the fourth quarter natural gas prices averaged 279 and oil prices averaged $58.40 per barrel, 63% of our revenue was attributed to natural gas production in the quarter down from previous quarter, due primarily the frac delays and shut-in to a fracking in north Louisiana Haynesville wells. LOE was $2.7 million for the quarter versus $2.2 million in the prior quarter. LOE for the quarter included $0.4 million for workovers. LOE excluding workovers was $2.3 million in the quarter versus $2 million in the prior quarter. Production and other taxes was $0.1 million versus a small credit in the previous quarter. Production and other taxes for the year totaled $1.2 million. Haynesville wells drilled in North Louisiana have severance tax abatement until the earlier of payout or two years and therefore the company's production and other taxes per unit of production is expected to remain low in the near term as new Haynesville wells are added to production. Transportation and processing expense was $1.6 million in the quarter which was the same as the prior quarter. Transportation and processing expense for the year was $6.2. Depreciation depletion and amortization or DD&A expense was $3.2 million in the quarter versus $3.5 million in the prior quarter and DD&A expense for the year was $12.1 million. G&A expense for the quarter was $4.7 million, which includes $1.5 million of stock-based compensation, the accrual of $0.9 million for potential performance bonuses and $0.1 million in non-cash amortization of office rent. G&A payable in cash for the quarter was $2.3 million and $9.2 million for the year. Operating income defined as revenues minus operating expenses totaled a loss of $1.2 million in the quarter versus operating income of $2.2 million in the prior quarter. Operating income for the year was a loss of $2.2 million. Interest expense totaled $2.7 million in the quarter, which includes cash interest of $300,000 incurred in the company's revolver and non-cash interest of $2.4 million incurred in the company's convertible notes, which includes $1.5 million paid in-kind interest or PIK, and $0.9 million of amortization of our debt discount. Capital expenditures for the quarter totaled $16 million and $41.8 million for the year respectively. With the majority of the expenditures being spend on drilling and completion cost for the company's Haynesville operative wells. The company is currently maintaining a $65 million to $75 million in capital expenditure budget for the year, but as Gil previously stated, we expect to accelerate in the second half of 2018 out of the asset sales proceeds. Moving back to our slide deck, we've included several Slides beginning with slide eight that shows how we trade relative to approximate 50 company peer group. Whether it is 2018 enterprise value to consensus EBITDA, net debt to EBITDA growth in EBITDA per million of capital expenditures or capital efficiency, we screen at or near the cheapest stock in the universe. We expect that to change as volumes in cash flow grow throughout the year. Slides 12 and 13 show our updated property slides which reflect our 22,100 net acre position in the Haynesville, 65,000 net acre position in the TMS, and 14,000 net acre position in the Eagle Ford. We have an average working interest of approximately 40% on our core North Louisiana acreage with approximately 250 gross, 100 net locations in inventory. Approximately half of the locations are capable of 10,000-foot laterals, with the remaining half split between 4,600-foot and 7,500-foot laterals. We have gridded our acreage with a plan to maximize long laterals, and expect to be in a position to swap acreage or drill joint wells with offset operators to further increase our long lateral inventory. We estimate approximately 1.2 TcF of reserve exposure at 2.5 Bcf per 1,000 feet of lateral in North Louisiana alone, of which we operate approximately 15%. We have updated recent industry activity on slide 14, including our two results mentioned in our release, the Wurtsbaugh 25 and 24, numbers 2 and 3 wells, which had 24-hour IPs of 25 million cubic feet and 30 million cubic feet equivalent per day respectively. There have also been notable recent completions by others in our area, including a common stock well at 27 million cubic feet per day adjacent to our northern most acreage at Greenwood-Waskom. We believe all of our acreage has now been de-risked with these latest wells. In addition to the highlighted completions, in the bottom-right corner you will see reference to our Cason-Dickson wells, which are approximately 10,000-foot laterals that are scheduled to commence fracking operations within a couple of weeks. We own a 92% working interest in these two wells, so the completion of these wells will add significant net volumes to our production stream. We are now able to show an abundance of well results on our decline curve analysis slides beginning on slide 15. With 56 4,600-foot laterals with an average profit of 3,500 pounds per foot and as much as approximately two years on a handful of wells. The composite production curve is generally following at a 2.5 Bcf per 1,000-foot type curve is shown in red. We also show 2.0 Bcf per 1,000 to which the composite curve is clearly outperforming. Moving to slide 17 and 18, which reflect our two 7,500-foot curves, we now have 87 wells with average profit concentration of 3,100 pounds per foot in our composite production curve, which again fits nicely with our 2.5 Bcf per 1,000-foot type curve. The older wells included in the composite curve are a handful of under-stimulated well, and we expect the composite tail results to pull up as the newer wells with higher proppant concentrations flow through over time. Slides 19 and 20, which show composite results from 35 10,000-foot laterals with an average of 3,100 pounds of profit per foot, are also tracking our 2.5 Bcf per 1,000 foot type curves. In general, longer laterals typically make better wells. And our current 2018 capital expenditure budget contemplates the vast majority of our wells to be 7,500-foot to 10,000-foot wells off of two well pads, or an average of approximately 9,000 feet per well. Our economics, as shown on slide 21 through 23, show how exceptional this play is at current gas prices. At $2.75 to $3.00 gas, we can generate a minimum of 36% IRR for a 4,600-foot lateral at $2.75 gas, to as much as 76% IRR at $3.00 gas for 10,000-foot laterals. As we have showed you before, our Haynesville returns are driven by very high realized prices being $0.12 to $0.15 off of Henry hub, low LOE, an average of about $0.05 per Mcfe, but even lower in the initial months. And no severance acts until the earlier of two years or payout. We have wells that have paid out in less than a year, so the current state of Louisiana severance rate of $0.11 per Mcf would kick in well before the two-year period ends, but is marginal as to the negative impact to our economics. When we operate our gathering fee averages about $0.25 per Mcf with a blended average of approximately 56 per Mcf in the play. In summary, our capital efficiency and full-cycle returns in the Haynesville are second to none as compared to other basins. And you will continue to see meaningful growth in volumes, a continuing expansion of our cash margin, and significant growth in EBITDA in 2018. We believe we can deliver these results to our shareholders from a drilling plan that lives within our means with very low outspend, provides increasing liquidity from a growing volume base, and allows the company to maintain very low [Technical Difficulty]. With that, I will turn it back to Anita to open it up for Q&A.

[Operator:]

Thank you. We will now begin the question-and-answer session. [Operator Instructions] The first question today comes from Neal Dingmann with SunTrust. Please go ahead.

[Neal Dingmann:]

Good morning guys. Rob or Gil, the completion issue had - now, when you look at sort of the plan for the remainder of the year, is that why the timing is a little more front-weighted or maybe just talk about - obviously you can't always control getting the frac crews and when you get the crews, but if you could just address how you are trying to sort of address that and plan around that for the remainder of the year.

[Gil Goodrich:]

Sure, Neal, this is Gil. I will say two things. One is, in the third quarter an operator came up to engage with some lower contracts to save us money. And so we felt like that was prudent and appropriate, which caused a little bit of delay from what we had anticipated back, say, late summer. And then the timing from the offset crews got held up and ended up being a good bit later than we had anticipated, even as late as the third quarter. For 2018, we tried to get in front of that even more. As you know, we just frac three wells early in the first quarter, all those went well. And we jumped out in front and picked up a crew now that will frac these two wells coming up here, as Rob said, in a couple of weeks. The next time slot probably doesn't get us until early summer. And we're currently working on this trying to secure specific contracts and firm dates, and doing the best we can to get several months out, so that we can meet our timing as we have in our guidance.

[Rob Turnham:]

And Neal, this is Rob, let me add something too also. We saw a lot of benefit in fully developing a section to minimize the parent-child relationship; therefore bringing all these wells on at the same time and maximizing volumes, but also obviously resulted in our necessity to shut in the offset wells. If you look at the rest of 2018 schedule, we'll have very little reason to shut in and in a big way in many of our locations. So, feel like a little less lumpy from the necessity to have to shut wells in going forward, which will help ultimately create a little more predictability on a quarter-by-quarter basis.

[Neal Dingmann:]

Rob, and that leads me up to my last question. What is sort of the plan for the remainder of the year? I know you've kind of thrown out the number of wells. Will most of those just be sort of one-off or what size pads? And I just want to make sure is that all mostly all around that Bethany Longstreet area, I just want to make sure what I'm looking at map on 13 to sort of see where they are, and kind of the size of the development for the remainder of the year.

[Rob Turnham:]

Yes, you bet. So the next, the Cason-Dickson wells are over in Red River Parish, what we call Thorn Lake. Obviously, that's a two-well pad. And those wells, as we said, get fracked early March, and come one - kind of early mid-April. After that we are moving the rig back to Bethany Longstreet area in a different area that's going to have minimum offset interference. So that'll be helpful and obviously can tie back in to our existing infrastructure once we move back. So really the vast majority, if not all of our wells are going to be two-well pads. They're going to predominantly be longer laterals, as we said, an average of roughly 9,000 feet. But it is a little bit more front-end loaded until we reach a decision on how much to accelerate in the second-half of the year. We have a board meeting next week. We'll have that conversation. That will obviously increase our volumes and certainly bring up the second-half volumes towards the tail end by the increased activity.

[Neal Dingmann:]

Very good. Thank you all.

[Rob Turnham:]

Thanks, Neal.

[Operator:]

The next question comes from Joe Allman with Baird. Please go ahead.

[Joe Allman:]

Thank you. Good morning everybody.

[Rob Turnham:]

Good morning, Joe.

[Joe Allman:]

Hey Gil, you talked about likely acceleration in the second half of the '18, what' trigger for that decision, or have you already made that decision and you are just hammering out details now?

[Gil Goodrich:]

Yes, decisions have been made. We had a call with the board continued on the closing of the East Texas, which occurred yesterday. And we are - obviously we have board meeting next week. We will hammer through exactly what we want to do, and when we want to do, and therefore what the magnitude of the acceleration is. So, stay tuned. I don't know exactly the timing, Joe, but I would say, hopefully, within the next couple of weeks you'll see obviously something from us in kind of detail and what plan to do with the activity increase.

[Joe Allman:]

That's really helpful. Then on the financial side, any out spin or are you thinking about just using revolver for that? And then kind of a follow-up on the financial, what's your plan for the convertible second lien notes?

[Rob Turnham:]

Yes. So I guess two things. One as we have said a couple of times in our prepared remarks, we will be paying off the exiting $16.7 million revolver plus we are going through a [indiscernible] based review right now which we should have results of fairly soon sometime in March or before April 1. And so that would be a piece of the puzzle. I think what we would like to do is do something that's prudent, yet there will be a little bit of out spin. But when you take the cash we had on the balance sheet as we entered the year plus the increase from the asset sale plus the increase in liquidity, I think we are going to be very, very comfortable coming up with a number that puts us in a position where liquidity does expand over the course of the year even with an accelerated capital plan. As for the second lien notes, I think as you are aware, come October this year, our MAKO [ph] provision steps down to the more reasonable number. And we've already had dialog at the board level about exactly what we do and when we do it. But we have plans to refinance those notes during 2018.

[Joe Allman:]

That's very helpful. And if I can just sneak one more in, just operationally, are you looking to tweak anything in terms of completions or even drilling or you are pretty much satisfied where you are technically?

[Gil Goodrich:]

Yes, Joe, really good question. In fact, it was a big topic at this DUG Haynesville Conference where Chesapeake, BP and others spoke also. One of the benefits of - and we gave compliments to Chesapeake for jumping out to 5000 pounds per foot on a 10,000 foot lateral instead of just continuing to do what you are doing but try to kind of understand the extent of how much you can push it. And there is no question that 5000 pounds per foot generates higher EURs. The question is what is your internal rate of return and return on capital since it's more expensive? And there seems to be a real consensus building among all the players. And we agree with this that perhaps to 3 to 4000 pounds per foot is more optimal. And not just because your EUR but mainly because the cash flow generated by spending less capital and optimizing and focusing on return on capital employed and less on just maximizing EUR. So, I think that has real kind of been fast forwarded not that there aren't future tweaks to what we are going to be doing, but most everyone is kind of falling in the 150 foot per stage interval and 3,000-4000 pounds per foot. And typically again, longer is better although again it's a recycle of your capital. Question as to whether 7500 or 10,000 make the most, so I think we are still in the camp, best rate of return are in the 10,000 per lateral. And then we will see where Chesapeake goes, but they are 15,000 foot lateral that they are drilling closer to our [indiscernible] area. Right now, we don't have any intentions of doing that, but we are watching closely.

[Joe Allman:]

That's very helpful. Thanks guys.

[Gil Goodrich:]

Thanks, Joe.

[Operator:]

The next question comes from Phillips Johnston of Capital One. Please go ahead.

[Phillips Johnston:]

Hey you guys, thanks. Just looking at your yearend '17 reserves, what sort of 12 month PDP decline rate in embedded in that PDP figure just I guess on a companywide basis?

[Rob Turnham:]

Yes, I'll take a stab at it. And this is going to be a little difficult get extremely precise, Phillips. But we would have said prior to adding these new wells that base decline was probably closer to 25%. But obviously you are adding these high volume wells that are baked in at or near January 1. So, I think probably 25% to 30% at year-end on the base, probably closer to 30 prior to adding fracs in the two wells. And then of course you are coming in with I call it 60% to 80% initial decline production on new wells. So baking that in is going to create a bigger number, but obviously generate better returns. So that's about as good. I can get offline and try to tighten that up for you if it's important.

[Phillips Johnston:]

No, no, that totally makes sense. Thank you. And then, just on the BP sale, looks like you sold close to 60% of your net acreage position there if my Math is right. I am not sure how much color you can give here given the agreement. But why not sell the entire asset and how did you guys and BP arrived at the number? Not in terms of value but just in terms of how much working interest or how many effective - were involved in the deal.

[Gil Goodrich:]

Yes, Phillips, this is Gil. So you are right. We can't say a whole lot, but your number is right. I think we are probably a little less than 60% of the Angelina River Trend] acreage expected for Haynesville well sold. How we arrived at that it was back and forth negotiations with BP as you would typically expect. It did include a look at three wells - excuse me a number of wells that we had down there and the acreage. But again, we can't talk about any of the evaluation relative to any of those things specifically.

[Phillips Johnston:]

Okay. So going forward, maybe I guess in the past you guys haven't really planned on drilling any wells there, but has your thinking there changed at all in terms of possibly drilling a well there?

[Gil Goodrich:]

Yes. I think that's great point. I think Rob may want to add a comment here, but that's a great point. So, the way we look at it is we have got so much to do nearly a billion dollars' worth of capital to fully develop in Northwest Louisiana block. That's where the bulk of the activity is. As we talked about before, the wells are deep and a little bit more expansive down there. So we viewed it as a transaction which pulls forward value that's really kind of not completely the back of the bus, but way down the timeframe on development in the inventory. Pull that capital forward, we can put it to work to the acceleration and create more value for our shareholders in the near term.

[Phillips Johnston:]

Okay, makes sense. Thank you, and congratulations.

[Rob Turnham:]

Thanks, Phillips.

[Operator:]

[Operator Instructions] The next question comes from Matt Sorenson with Seaport Global. Please go ahead.

[Matt Sorenson:]

Hi, good morning gentlemen.

[Gil Goodrich:]

Good morning, Matt.

[Rob Turnham:]

Good morning, Matt.

[Matt Sorenson:]

I was wondering if you could talk some on the offset fracking and the impact that had on your Q4 production. I think you had mentioned that it might have impacted production by about 3 million a day. And Rob, you mentioned that the risk of that impacting your 2018 program was lower. Can you talk some about how your guidance anticipates the shut-ins going forward?

[Rob Turnham:]

Yes, that's in cycle, Matt. Certainly, drilling everything in a section, as I have just mentioned, impacts the volumes for quite a while, and it was really two-fold on the shortage of fourth quarter volumes. It was delays on starting the frac. A little bit of delays on getting the frac done and the shut-in of the offset wells. So, I think we try to be pretty transparent on the disclosure relative to what happened in the fourth quarter. Going forward as we complete the two case in Dickson, there is really no significant volumes that we have to shut-in while fracking those wells. So that's going to be helpful. When we move back to Bethany-Longstreet, the next two wells that we have planned are quite a bit of distance away from the existing production. So, if we have to shut-in anything at all, it's not going to be meaningful we think. So I think the rest of 2018, now it can move around a little bit. In particular we are operating about as we project about 80% and we have a non-operated position on 20%. And we can't control what happens on the non-op parent wells obviously and where those wells - where they shut-in those wells. But I would say going forward, Gill, kind of mentioned you could have some choppy or lumpiness based on timing, but we are going to have far less shut-ins affecting the volumes for The rest of our locations for the year.

[Matt Sorenson:]

Okay, great. Thanks. And my one other question is that, we've had a number of operators talking about incorporate and re-fracs under the 2018 program, is that something on your radar?

[Gil Goodrich:]

Well, this is Gil. Matt, we are looking at it very closely. We think that the body of evidence is growing and indicate very attractive rates return from the refrac will be clear about that. These are not just complete open-hole refracs; these are when you go in and clean the well bore out, run a new three and-a-half inch line inside of the old existing five and-a-half inch kiting and go to plug-in peripheral operations. Those kinds of the refracs have actually been quite successful thus far. For us, however, we have probably 90 wells currently in Northwest Louisiana that will be subjected to potential refracs in the future. But we are going to let that continue to play out and going to spend our capital this year for new well drills.

[Matt Sorenson:]

Okay, thanks, great update.

[Gil Goodrich:]

Thanks, Matt.

[Operator:]

The next question comes from John White with ROTH Capital. Please go ahead.

[John White:]

Good morning and congratulations.

[Gil Goodrich:]

Thank you, John.

[Rob Turnham:]

Thanks John.

[John White:]

Your Haynesville Hub Street continues. If you were to expect -

[Rob Turnham:]

We expected to continue further. That's the beauty of the play as we have 85 wells and we are drilling between all wells. We are tying into existing facilities and we feel like we got the completion recipe now to where we honestly pretty consistent results going forward and that's the beauty of the development play like we are in.

[John White:]

Yes, it looks like a plenty of running room. So if you already addressed this I apologize, I got on the call a little late, but any comments on oil field service inflation or cost numbers?

[Rob Turnham:]

Yes, this is Rob again. It's interesting because of increased capacity on the pressure pumping sides in the Haynesville, it's held key cost down and in fact we are seeing more competitive bids than what we saw six months ago or when we drilled our first set of wells and that no guarantees in fact in last but currently passive in the course of the operation on the pressure pumping side, they've been able to kind of reduce their cost structure as we involve from their provider. So I think in general, it would have been pleasantly surprised that would not see in the same type of escalation and service cost. So that being said, it's not uniform across the board. We do see slightly higher rates of the small fraction of the completed well cost. The mom and pop operations that you supplement a big ticket items like pressure pumping are probably up a little bit but in general our higher fees and our current design at or below where we were originally. So we feel very good about that.

[John White:]

Well, that is a pleasant surprise and as you noted it runs counter to what we are seeing in some other basins. So thanks for taking my question.

[Rob Turnham:]

Thanks John.

[Operator:]

The next question comes from [indiscernible] with Johnson Rice. Please go ahead.

[Unidentified Analyst:]

Hi, good morning. How are you doing?

[Rob Turnham:]

Good. Good morning.

[Unidentified Analyst:]

Yes, and for Rob just wondering. I just had a couple of questions; I guess one to continue on the theme of completion cost. So we heard Comstock talk about the use of local sand sourcing, or clear on wondering if you all thought about that, or talked about it or kind of where the…

[Gil Goodrich:]

This is Gil. Yes, we are aware, pretty good a bit about what's going on a number of operators have begun the pump at least some blend of local sand. I think it really is, it's a granularity and it's a crush strength issues. We are looking at that, we made no form of decision about doing it. The cost sands are real. So I think if you see the play on forward - going forward to the extent that the local sand can be utilized in high quantities that could be a meaningful move now more than in overall completed well cost. So I'll say good, which we will kind of in a wait-and-see mode and a technical look at it and contemplating maybe using some percentage of it mix with our other way.

[Unidentified Analyst:]

All right. Thank you. And then, maybe another question just kind of a wait-and-see but with common stocks wells of it Greenwood-Waskom. I was wondering where if that it was going to come into play in 2018 or also imagine just fix you in that 15,000-foot lateral up there, just you know, where that fits in and what do you think about it?

[Gil Goodrich:]

Yes, so we really like here congratulations to our friend to common stock, all our acreage up there is held by production as all of our northwest Louisiana acreage is and I think we got so much to do, let's say we had about a $1 billion worth of capital to fully develop our north Louisiana block, we built under real 16 wells, none of those 16 wells are currently stated to be up there. But certainly as we get into 2019, it's highly likely you'll see that on couple of wells on some real acreage.

[Unidentified Analyst:]

Great, thanks. And then, one more just back to your acreage sponsorship in the Haynesville kind of what you all seeing in-house and then in the basin and kind of amongst your retail players in general.

[Rob Turnham:]

Sure, this is Rob. I mean, we are continuing to pursue that, it makes sense for both parties to maximize long laterals to get out of each other's here from a budgeting standpoint. But once we've done today, it will then just equal or similar net royalty or net revenue acres and we hope to continue to do that and we are in conversations with others about the potential of doing that. So it makes sense for both parties we think but not going to report today.

[Unidentified Analyst:]

Great. Thanks and great quarter.

[Rob Turnham:]

Thanks.

[Gil Goodrich:]

Thank you.

[Operator:]

[Operator Instructions] It appears to be no further questions. I would like to turn the conference over to Gil Goodrich for any closing comments.

[Gil Goodrich:]

Thank you indeed. Thank you everyone. We appreciate your time this morning; really feel good about where we are. Off to a good start here in 2018, and we look forward to presenting our first quarter numbers to you in early May. Thank you.

[Operator:]

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