Comstock Resources, Inc. (CRK) Q3 2017 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Q3 2017 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Jay Allison, you may begin.

Thanks, Jiji. And I know this is a busy hour for earnings so call of – people who are attending thank you listening to us. Welcome to the Comstock Resources Third Quarter 2017 Financial and Operating Results Conference Call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentations. There you'll find a presentation titled Third Quarter 2017 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; and Dan Harrison, our Vice President of Operations is making his first conference call appearance today. Dan joined Comstock in 2008. He graduated in 1985 from LSU with Petroleum Engineering degree and has held positions at Sun Exploration, Oryx, Pioneer Natural Resources, [Pras] Energy, Cimarex Energy in various capacities including production engineer, drilling engineer and operations engineer. Our entire operations team has delivered stellar performance in our third quarter as Dan will discuss during his reports, so welcome Dan. During this call, we will discuss our third quarter operating and financial results as well as covering our outlook for 2018, if you go to Slide 2. Please refer to Slide 2, in our presentations, and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Our 2017 third quarter summary slide 3. A summary of our third quarter is outlined on Slide 3, where you can see we had a solid quarter driven by our successful Haynesville shale program. The recent fall in our thought process is not correlated to the company's operating performance and outlook for next year as we hope to demonstrate for today's call. Our natural gas production has grown by 42% as compared to the third quarter of last year and is 51%, if you exclude the production from the properties we sold last year, oil and gas process also improved in the third quarter as compared to 2016. Our natural gas process is 14% higher and oil process was 10% higher than the third quarter of 2016. The higher natural gas production caused our sales to grow by 40% to $70 million and our EBITDAX increased by 69% to $50 million. Cash flow from operations for the quarter was $32 million, a [553%] increase over 2016. Our Haynesville drilling program is driving the production increases and improved financial results. All of our Haynesville and Bossier well drill continue to perform above our top curve. The joint venture we have with USG has allowed us to continue to grow our inventory at Haynesville and Bossier shale locations which set at over 800 today. We are very focused on improving our balance sheet by growing our cash flow and EBITDAX and believe we will be positioned in early 2018 to refinance our expensive debt. We announced today that our Board of Directors has approved the potential sale of our Eagle Ford shale properties which could generate proceeds of $200 million to 300 million. We typically don't give a target range but we know each one of you would be asking selectively. The important point is that the Eagle Ford asset is a tier 1 oil asset and tier 1 basin that we will aggressively market and we intend to use the proceeds to refinance our balance sheet. The proceeds from the sale allows our growth in reserves and EBITDAX shall allow us to retire in part and refinance our first and second-lien bonds. We have total liquidity of $150 million which is more than adequate for us to carry out our planned 2018 drilling program. If you go to slide 4, an important slide for the Haynesville shale JV. As we announced on October 11, we have we've expanded our joint development program with USG which is outlined on slide 4. The initial activities of the joint development program have been focused primarily in Caddo Parish, Louisiana where to-date USG has acquired over 7,000 net acres targeting the Haynesville shale allowing Comstock and USG to drill 34 extended lateral wells. We have drilled three 10,000 foot lateral wells so far and are currently drilling a fourth well. Completion operations on these wells will commence later this month. We are participating for a 25% working interest in these wells and may increase our working interest participation by mid-2018 to 40%. USG is also participating in four of our wells being drilled targeting the Bossier formation in Sabine Parish, Louisiana. USG will pay us 1.4 million for the Rock to participate for 50% of Comstock’s working interest in each of the four Bossier wells 400,000 that amount is only paid [indiscernible] production targets after six months. As a result of making a commitment to the mineral owners to drill the four Bossier wells we also are under lease on an additional 640 acres adjacent to [indiscernible] were granted a reduction in the royalty of these wells from 25% to 18.75% and we are assigned an additional 12.5% working interest in the wells by drilling these four wells. USG also agreed to participate in drilling program on certain of our acreage in Harrison County, Texas that will target the Haynesville Shale. We have approximately 7,000 net acres in Harrison County, Texas which has 34 Haynesville Shale locations on this acreage. Similar to the Sabine Parish agreement will be paid 1.1 million for each location per acreage in infrastructure related to the well location. The participation of USG will allow us to acquire additional acreage in this area which will add additional drilling locations to our inventory. For each well drilled in the program except for the four Bossier wells we are paid $80,000 per well for engineering and geological services. Now I will turn it over to Ronald. He will report on our financial results. Ronald.

Thanks Jay. Slide 5 shows the growth in our natural gas production being generated by our Haynesville shale drilling program. In the third quarter our natural gas production averaged 217 million per day up 51% from the third quarter of 2016 and up 14% from this year's second quarter if you exclude the production we divested in December of last year. In October we averaged 213 million a day and we expect to see the fourth quarter average in the neighborhood of 240 million per day and then with the drilling program in 2018 which is fairly similar to this year in cost we estimate that our 2018 natural gas production would average between 250 to 270 million per day. This is little higher than the press release guidance as those estimates were very conservative. It's always important to point out that our Haynesville operations are in an area with a substantial regional natural gas price advantage compared to the Northeast markets and we have not committed to onerous firm transportation and gathering arrangements like many of the other large things Haynesville producers. As shown on slide 6, our regional basis differential to Henry Hub is only around $0.12 for the last 12 months and while the transportation to Henry Hub from the Northeast which is about 1,200 miles away is averaged $0.94 for the same period. Gulf Coast industrial demand, exports to Mexico and LNG exports continue to grow in the Gulf Coast region. Our gathering and treating costs to get our gas to the major markets is around $0.22 given us high price realizations which are very important in this current lower gas price environment. Slide 7 shows our hedge position we put in place to lock in the high returns of the Haynesville Shale drilling program. We had 99 million per day hedged in the third quarter at $3.38 per Mcf, it's the similar amount hedge for the fourth quarter at the same price. And we are currently working on putting in hedges for our 2018 program and we target to having 60% of our gas production hedged as we get into 2018. On slide 8, we summarize our oil production. Our oil production averaged 2,500 barrels per day in the third quarter showing continuing decline due to the lack of any drilling activities since 2014 and the sale of our Eagle Ford shale properties in 2015. Most of our oil production currently is from our Eagle Ford shale properties in South Texas which will probably be shown as held for sale by the end of the year. We expect oil production in 2018 prior to this sale will approximate between 2,000 and 2,200 barrels per day. Slide 9 shows how much production we had shut-in in the first three quarters of this year. Shut-in natural gas production averaged 2 million per day in the first quarter which was related to well shut-in for offset frac activity. In the second quarter the shut-in production averaged 8.2 million per day much of which was related to severe storms and tornadoes at our Haynesville operating area in May of 2017, which caused electrical power outages in the region. In the third quarter our shut-in production averaged 8.9 million per day. This is mostly shut-ins due to the necessary -- that were necessary due to offset frac activity for either our operations or for activity by offset operators. Our oil production has been shut-in due to offset frac activity from nearby operators in the Eagle Ford area. In the first quarter we had about 105 million barrels per day shut-in, 59 barrels per day the second quarter and 56 barrels per day the third quarter. On slide 10, we show how our producing costs continue to improve as we shifted toward drilling our lower-cost Haynesville shale properties versus the higher cost oil projects. Operating cost improved at $0.73 per Mcfe this quarter as compared to $1.48 in 2014 and at a $1.10 in 2016 with much of our production coming from new wells in the Haynesville shale which were exempt from production taxes in their first couple of years. Our production taxes averaged $0.07 in this quarter as compared to $0.36 back in 2014 and $0.08 in 2016. The field level producing costs were also down to $0.44 in the third quarter as compared to $0.97 in 2015 and $0.76 in 2016. Our depreciation, depletion and amortization per Mcf produced has also come down dramatically and was $1.52 per Mcfe this quarter as compared to $5.34 in 2014 and $2.26 in 2016. The improvement is due to the low signing cost of our Haynesville Shale wells. If you exclude the Eagle Ford operations, our total operating cost per Mcfe would have been $0.57 this quarter which includes gathering, production, taxes and lifting and our DD&A per Mcfe would've been $1.27. So, on a pro-forma basis for the divestiture that we hope to complete next year and post the refinancing of our debt, our cost structure will be one of the best in the industry. On slide 11, we summarize the third quarter financial results. The growth in gas production improved prices and lower operating costs continued to drive improvements to our sales and cash flow. Our natural gas production increased 42% and natural gas prices increased by 40%. As a result our oil and gas sales this quarter were up 40% at $70 million that's compared to the third quarter of 2016. Our EBITDAX was at 69% at $50 million and our operating cash flow of $32 million was substantially improved from the cash flow of only $5 million that we had in the third quarter 2016. As I pointed out earlier our producing costs have also come down substantially. Lifting costs in the quarter were down 12% and our DD&A was down 13% due to the improvement in the DD&A rate. This is all despite the 34% increase we had in overall production. Our G&A costs were up in the quarter by $2 million reflecting the increase in our activity level as compared to last year. For the quarter we reported a loss of $24.7 million or $1.67 per share. This loss includes several unusual items including an unrealized mark-to-market loss on the hedge contracts of $2 million. Non-cash amortization of the discount recognized on the bond exchange we completed last September of $9.9 million which just simply offsets the $100 million gain that we recorded last year and a loss on the small property sale we completed this quarter of $1 million. If you exclude these items the net loss for the quarter would've been $0.80 per share. On slide 12, we recap the financial results for the first nine months of this year. Natural gas production grew by 24% and gas prices increased by 37%. Also we had an improvement in oil prices of 30%. So the result was our oil and gas sales for the first nine months of 2017 were up by 45% to $187 million that's compared to the same period in 2016. Our EBITDAX is up over 100% to $128 million and operating cash flow of $74 million was substantially improved from the cash flow deficit of 17 million that we had in the same period in 2016. The improvements in producing costs were also contributing to the improved financial results along with the higher gas production and the improved oil and gas prices. And our lifting costs were down 18% in the first nine months of this year. Our DD&A is down 17% due to the lower rate. Overall our G&A cost were up by 24% and for the nine month period, we reported a loss of $69 million or $4.74 per share. This number also includes the same unusual items that if you exclude these items we would have had about $3.60 loss per share. On slide 13, we covered the balance sheet into the third quarter. We ended the quarter with $25 million of cash on hand and $175 million of total debt outstanding based on the principle amount. If you include the undrawn credit facility and the available pay in kind interest of our first-lien bonds that we are continuing to pay in cash, our total liquidity is relative the same as it was throughout most this year at $150 million. The potential sale of the Eagle Ford Shale properties should allow us to retire in part and refinance in part our first and second-lien notes. The sales proceeds combined with the new secured line credit facility and unsecured bonds should give us the necessary tools to reset the balance sheet and substantially lower our interest cost. We are targeting March of next year to kind of get all this accomplished. Slide 14, recaps our capital spending for the first nine months of this year. We spent $126.7 million in this period and we drilled 17 new Haynesville extended amount of wells which were about 13 net to our interest. We expect to spend about another $38 million in the fourth quarter to finish up our drilling program this year. On slide 15, we lay out a preliminary drilling program using the three operated rigs that we currently have running. We will continue to refine and change this program as we get closer to the end of the year, this is earlier than we usually put this out that we wanted to kind of show that we are dedicated to running the program that's going to be funded exclusively with operating cash flow and this is a conservative program that we think meet a lot of our needs. So we expect to have two of the rigs that we have operating drilling wells under the joint development program with USG and then we expect to have one drilling on legacy acreage in the Haynesville Shale. So under this plan we drilled 26 wells or 13.8 net wells, all Haynesville Shale wells in 2018 and this would cost approximately $145 million. We also expect to spend another $14.8 million to complete wells that were drilled in 2017 that will carry over into 2018 for completion. And then, we have two refracs, in-line of refracs budgeted in this budget for $6.7 million. Then we have budgeted an additional $3.4 million just for other miscellaneous activity. Depending on the industry conditions that we experience in 2018 we can increase or decrease this budget as circumstances warrant. One of the potential increases is that we may add a Bossier Shale program following up on the four wells that we are drilling here at the end of this year. Dan will now take over to bring you up-to-date on our Haynesville drilling program.

Thanks Ronald. I am excited that to take over for Mac and update you on what's going on with our Haynesville Shale operations. You can see on slide 16, is a good overview of the Haynesville Shale and Mid Bossier Shale play in the North Louisiana and East Texas. All 69,000 of our net acres in the Haynesville play is reflected in blue on this map. We operate the majority of our net acreage position and have an average working interest of 78.7% over the 88,000 gross acres we have an interest in. The average net revenue interest in our acreage is 80.5%. We are drilling 25 wells in our acreage this year and tentatively plan to drill a same number next year. As most of you know, the Haynesville Shale is undergoing resurgence in recent years as longer levels and larger stimulations must have led the much higher production rates and EURs. As a result, which also relayed that the Haynesville Shale wells have strong returns in today's $3 natural gas price. The location of the Haynesville near the Henry Hub combined with our competitive gathering and treating contracts gives is the premium natural gas market for Haynesville production. We recently finished remapping our acreage after the completion of acreage swaps of two offset operators as well as adding new acreage. We have been able to greatly increase our inventory of 10,000 foot laterals or two section laterals as we call them which now stands at 163 in the Haynesville and 183 in the Bossier. Our bread and butter liable of 75000 feet of section and half laterals stand at 97 in the Haynesville and 88 in the Bossier. And our single section inventory stands at 200 in the Haynesville and 118 in the Bossier. So this gives us a total of 849 locations in the Haynesville and Bossier Shale and 82% of in these are operated by us. In addition to the Haynesville and Bossier opportunities we also have 285 horizontal Cotton Valley locations to drill. We also have a very good inventory of refrac opportunities across our 115 older vintage Haynesville producers based on the strong results that have recently been posted by some other operators in the play. Flipping over to slide 18, slide 18 shows a comparison of our Gen 1 and Gen 2 completion IP results average over 1,000 feet of completed lateral length. As a reminder Gen 1 design uses 2800 pounds per foot proppant loading applied over 250 foot frac length involving 5 perforation clusters with 50 foot spacing. Our Gen 2 design uses 3800 pound per foot proppant applied over a 150 foot frac length also utilizing 5 clusters but at 30 foot spacing. Our 13 Gen one wells gave us 3.3 million cubic feet a day per 1,000 feet of lateral, while our 15 Gen 2 wells have given us 4.3 million a day per 1,000 feet of lateral. So Gen 2 completions have given us a 32% improvement in our IP ration over Gen 1. As you can see on both slides 19 and 20, it shows you all 27 Haynesville wells plus the one Bossier well that we had put to sales since the beginning of our program in 2015. The wells with the red color also are 13 Gen 1 wells drilled in 2015 and in the first three quarters of 2016. The gold color are also all the Gen 2 wells we have drilled since late 2016 up through the current date. Since our last conference call we have completed three additional Haynesville Shale wells. The average initial production rate of these wells is 29 million cubic feet per day. Our Headrick 14-11 number 1 well was drilled to a total vertical depth of 11618 feet with 7168 foot completed lateral. The wells’ IP was at 33 million per day. The Headrick 14-23 number 2 well was drilled similar vertical depth of 11496 feet and had 7429 foot completed lateral. Its initial production rate was at 35 million per day. The Grantham 30-31 #1 well was drilled to a total vertical depth of 11,198 feet with a 8,456 foot lateral, and was tested with an initial production rate of 20 MMcf per day. The initial rate on the Grantham view was power water production of disposal capacity. We have recently completed frac in the Derrick 21 #2 and the Derrick 21 #3 wells both with 4,550 foot laterals and just about both of wells – today and we’re completing the BSMC 18-7 #1 Bossier shale well that has a 7,489 foot lateral and as of today we’ve seven Haynesville shale horizontal wells waiting completion. You can see on slide 20 again this is the same data presented on the previous slide. We share the wells initial production rates per 1,000 feet of completed lateral. This normalizes the results between the wells and better depicts the improved results on the Gen 2 wells versus the Gen 1 wells. On slide 21, we display how Haynesville and Bossier wells that has sufficient production history of performing against our 7500 foot type curve. The red curve represents the average of our 12 Gen 1 wells which we started drilling in early 2015. These wells now have several years under the belt and continue to perform above our type curve. The purple curve represents the average of our eight longer lateral Gen 2 wells which are outperforming the Gen 1 wells so far. The light blue curve which is the average of our six shorter lateral wells which were also completed with the Gen 2 design. As you can see they are performing close to the 7,500 foot type curve even with 2,000 foot or less lateral length. And finally, you can see the green curve that represents our one Bossier well which has now produced well over 600 days and is outperforming the Gen 1 Haynesville wells. On slide 22, we have normalized the data on the previous slide to reflect the production per 1,000 foot of completed lateral. The Gen 1 curve is the average of our 12 wells drilled in 2015 and 2016 and is shown in red. The average lateral length for these wells was 7194 feet. The green curve is the Bossier well drilled in 2015. The new curve is the average of all of our 14 Gen 2 wells which had an average of lateral length of 6454 feet. You can see the Gen 2 wells are outperforming with Gen 1 wells on the type also. On next slide, slide 23 this shows the rate of return forecast cases and the underlying assumptions for our Gen 2 wells that are NAMEX, natural gas prices of $2 up to $3.50. That’s larger the production we expect from each of these different Haynesville wells we drill. We have updated the cut off reflect what we are expecting to spend in 2018. Even with the higher service cost we still have strong returns for these wells. As you can see at a 250 gas price are greater returns of 34% for our short laterals and around 41% for the horizontal wells drilled to 7500 feet and beyond. At $3 gas price the rate of return increases to 60% for the shorter laterals and up to 70% for the longer laterals. And with that I’ll just wrap that up and now turn things back over to Roland.

Right, I will take it from here. Thank you, Dan. If you go to the outlook which is slide 24, let me refer you slide 24, I’ll cover the outlook for the reminder of the 2017 and 2018. Our high return Haynesville Shale assets are driving our strong growth this year as Roland has demonstrated and Dan has demonstrated. Our Haynesville completion has transformed the Haynesville Shale at one of North America's highest return natural gas price in our acreage position gives us over 800 featured drilling locations. We are expecting our natural gas production to grow by more than 40% driven by 26 well drilling program, a similar 26 well drilling program in 2018 will allow us to go natural gas production by at least 30%. The production increase will cause our EBITDAX and cash flow to continue to grow and it's important to note that we have already grown our cash flow to fully fund the drilling program. Our already low cost structure has continued to improve with new low cost Haynesville Shale production and to third quarter there we reported on today our lifting cost per Mcfe have decreased by 34%, our DD&A per Mcfe has improved by 35% as compared to 2016. Balance sheet and liquidity continue to improve as we grow our cash flow and EBITDAX the potential sale of our Eagle Ford shale assets combined with growth in EBITDAX should allow refinancing of our secured debt in early 2018 as Roland has mentioned. For the rest of the call we will take questions from the analyst to follow the company. So Jiji, I’ll turn it back to you.

[Operator Instruction] Our first question is from Michael Kelly from Seaport Global Securities. Your line is now open.

Hey guys, good morning. Jay, Ronald I am just a stupid equity guy here so you are going to have to maybe lay out the playbook how you proceed with this asset sale and debt refinance, I guess I’m curious really kind of what you think the company will look like post execution what in your mind is the critical steps to actually make this happen and then what concessions if any you think you’ve to give the bond holders to make this happen as well? Thank you.

Yes thanks. Yes I don't know that we can lay out the playbook. I don’t think that makes a lot of sense. But I think we think that with the additional cash generated by the divestiture of the assets there will have all the tools in hand to refinance all our bonds. And so, potentially we call all the bonds, save the shares that were designated by the shareholders for the conversion. So that's our goal. So I don't, there is certainly I mean certainly no concessions to be made to the bond holder. So I think they expect and they will get 100% repayment of their bonds and we think we – by growing the reserve base, the cash flow we will be able to refinance a lot of that debt and then use some of the cash to retire some of that debt. So that's the playbook.

Yes Mike, I want to come in on that that's a, if you look at the recap the company had in November of 2016 I mean the second lien bond holders made a concession to be converted into equity and if the stock is 12-32 then that will happen. If it doesn't which I think that's been the recent pull back in the stock because of this uncertainty if it doesn't what will happen. So what we got to do today and today is the first time we have been able to do this publicly is to say we have added more Haynesville acreage for our partner USG. We have increased our EBITDAX materially. We funded a program we think would grow production 30% to 40% next year for 2018. We have funded it already. And what we think will be our EBITDAX number and we should have some material reserve. So if you take that and then you look at a pity 2-3 dollar oil cost whatever it is today, you look at tier 1 oil asset, which is our South Texas Eagle Ford because we took that 18,000 -19,000 acres which has helped our production. We grew from zero oil to almost 13,000 barrels a day. We hadn't spent any money on it really since 2014. So it’s 2,200 barrels, 2,300 barrels per day but we set the infrastructure and to drill the remaining 300 locations. So I think our timing will be good to monetize that I think that will give us that extra chip that we need as our borrowing base is growing because it's growing materially and our goal is to go back to much less expensive money and a balance sheet it’s in the middle of a fairway and for everybody to be rewarded for what all they have done I mean whether you are first-lien owner or second-lien or an equity owner, I think we truly have protected everybody. And there is something that can happen because [indiscernible] as many shares or any shares we tend to buy out the second lien positions and that be even better for the equity owner let's just say we’re that much stronger as a company. So that's why we even gave a range of what we thought the Eagle Ford shale, we don't really know that's a target range, it's an indication range so the goal is that we will use that to refinance our balance sheet and I think it look wonderful and Dan has done really, really good job taking up the time for Mac and so also the whole team. So I hope that helps.

Yes that helps. Let me just pick a little bit more on that I mean what in broad strokes of course, I don’t want you to – the whole playbook here but in broad strokes where do you think this puts you if everything goes as planned maybe if we are looking at leverage metrics how do you think you come up the other side of this what's kind of the goal in your mind?. Thanks.

Well, obviously our goal is to get the total leverage down to under 3 times, but I think that as you could see from recent deals done in the market that their company is at much higher leverage issued new bonds, so but our goal is to get to that under 3 times and that's kind of a middle of the fairway type of balance sheet and we think that's achievable. The Shale Eagle Ford will be big step toward helping reduce the overall debt level of the company.

Our goal is not to kind of put a band-aid on our balance sheet either. I mean our goal really is to fix it and if the interest expense is killing us it's not all liquidity we have liquidity. It's not our inventory of location. We have increased our inventory. It's not the quality of our assets. It's not the profit margins we have. It's just a sheer amount of expensive debt we had to put on to dance of way through the worse stock we have had in the generation. So and I think we will continue to do that and like Ronald said if we get our leverage below three times I mean I think on the equity side which you are talking about I mean I think the stock class will explode in value and that's our goal because we own a lot of it.

Good stuff. That's great color and I would concur with whatever you just said. Just maybe one operational one from me, if I will look at the number of wells that you put out for next year, 26 gross if I just divide that by three rigs it's each rig line average an 8.6 wells annually I am not sure if that's the right way to look at it if there is the third rig that's being phased in later. How should we think about each rig lines capabilities now and the potential for that number to have some sort of fluctuation on the gross wells are? Thanks.

Yes, I will answer this correctly for Dan and -- but basically I think that the base budget there doesn't assume that one of those rigs get released before probably late third quarter of next year. So but generally, a lot of the wells are 10,000 foot laterals so they definitely take longer so it's a – they are going to take longer to drill. So I will let Dan kind of comment and we will phrase for those.

Yes. So really the majority of the locations we are going to be drilling next year too wells we have got a lot more the 10K lateral we are drilling next year. They do take longer you can’t get quite as many wells per year. We do have just one of the rigs is going to be running in our legacy area we are going to have two of the three rigs that will be running on our JV acreage. We will be participating in a lot lower working interest to keep our capital requirements so much lower but as Roland said we have got with the plan now maybe roll off one of the rigs towards the end of the next year.

One other thing Mike you asked and I think it's a key question. What is your playbook even though we can't tell you what it is totally I think today the market can see we have one. We are not going to tell you that we are going to attempt to sell Eagle Ford but until we put it in writing and have somebody to do it, maybe we don't. But today we are going to do that. Our goal is to have EBITDAX of $50 million well you didn't know that until this morning at 5:45 that we do that so our goal is to grow our JV acreage. You didn’t know we really brought it 7000 acreage to this morning. Our goal was to add some value in Texas in the Marion, Harrison County. I guess what we bought a new SG which has great muscles. There is a financial partner and we will drill Haynesville wells there. We want to drill more Bossier wells. So we go to the mineral owner and we know them since 1995 and they have got us fixed two or three and we are working deal so we drill Bossier wells too with the partner we promote the partners. So all these things are part of the playbook that are accretive and I think as it plays out month to month to month I think will get stronger and stronger and stronger and stronger and stronger. I do believe our worst days are in rear view mirror. So we will see what happens to commodity prices but from the operations financial side it couldn't be better than –

Great guys. Thanks for answering my questions.

Thanks Mike.

Thank you. And our next question is from Ronald Mills from Johnson Rice & Company. Your line is now open.

Hey good morning Jay. Question on maybe for Dan, but when I look at your Haynesville position it's gone up about a 1,000 acres I am assuming that maybe related to the JV acreage increasing yet the number of total Haynesville and Bossier locations went up by plus or minus 20%. What's driving the increase in the number of locations given a fairly similar amount of acreage and then also there is a big shift in terms of 56% of the Haynesville locations you’re now 7,500 foot to 10,000 versus 40 so it's a combination of what's driving the absolute level of inventory increase and then also is it acreage drops is driving the higher percentage of longer laterals?

Yes. We haven't really Ron refreshed that numbers since last year. So there is a lot of things have happened and we just finished the remapping but we did some pretty very productive trades with two operators in the Haynesville and that added new locations that before we didn't have enough acreage to have a location but it also definitely helped on the more longer laterals especially in the 10,000 foot area. The JV operations which doesn't show up a lot in the net acres that was added a lot of locations. They really – the number before really didn't include the JV. So I think it's and then I think a lot of work in Harrison County since we have done a ton of work locations so there expects before we didn't have any extended laterals in Harrison County. So yes, I think it's just a – it's really a one that number is very stale that has been out there since last probably almost a couple of years old number. So this reflects all the work that we have been doing to enhance the inventory across the board. So it's rigid snapshot today but obviously didn't happen just on the last month. It's the combination of everything including the new relationship with USG that has built up the inventory.

And well, I think it's driven by the importance of locations. When we started the first Haynesville well in February of 15, it didn't really matter how many locations we really had because we didn't have one extended lateral has completed well by the end of 15 you have got ten including Bossier by 16 you still don’t have much money. You drilled three wells and you drilled some more and then you get serious because you got a partner and any contiguous acreage you can have, you tried to have it and then you add like Roland said the Vast Marian and Texas so you end up with what we have now. A lot of trades happened last year. We saw Chesapeake and other sell out some of their acreage so the new acquiring operators were able to trade some acreage that they want, we want we have more locations and so -

And we didn't report those earlier because those hadn't closed yet. That takes a long time to complete acreage swap and these took almost a year and I think we are really waiting to get those trades completed before kind of remapping or representing the numbers and so all that kind of came together in the third quarter and so I think this is a great base and it will – we hope to continue to add locations as we continue to work our acreage positions.

Do you mind if I do these exercise a couple of times I know there have been some recent A&D transactions over there where Rockcliffe has amount of couple of assets. Can you talk about any recent activities of people drilled extended lateral wells with the newer completion techniques? What's driving the confidence to start including those locations?

Hey Ron this is Dan. So we got – we have had the history on we drilled approximately 7 Haynesville wells over in that area back several years ago in the first go around in Haynesville. We have got pretty good handle on, we kind of worked with multipliers are for the newer, larger stimulation, more intense stimulation jobs are. So when you go just look at those multipliers and go apply to some of the wells in those areas we feel like the economics are very favorable to drill in that area. We just have it been through into that area yet but there was another operator that has drilled some newer, they didn't drill longer laterals but they did drill a handful of shorter laterals and that had some very good results. So everything is basically based on that information.

And really what's changed for us Ron is that we have done extensive land work and add into that area to allow us to be able to drill longer laterals and so and traded acreage, moved acreage, lease new acreage, acreage does not drill-able and some of that is not even taken out of numbers so there I think before we just hadn't done all that work or had even had ability to drill the longer laterals and we think that's important to have the economics to be on par with other programs is to be able to drill the extended laterals and that's why we now have created the ability to drill the 34 so long laterals over there. That's the work in process. We really expect to be able to continue to add on acreage and do trades and make more of our acreage over there drill-able and the long units. So it's an area focus now and especially with in partnership with our JV partner we have the resources to put some capital in to getting new leases. I know these wells are going to get drilled.

What is interesting Ron you can go back where to probably 08 when we drilled the first Haynesville well and the first four wells we ever drilled back in 08-09, let's say one was Bossier kind of where we are drilling the Bossier today. Second one was in Waskom, Harrison County. Third was in Caddo and we ended up in [indiscernible] so kind of those four may not be an exact order but that's where we targeted growth back in 08-09. So that goes back and Dan joined us in 08 so that goes back to the history and I think that's one of the reasons we had USG as a partner because I said you got depth of history we need that. Well, that's a good thing because this is win-win for everybody.

And then on the updated well cost, you have increased more in line with what other guys have been talking about for 7500 and 8500 in 10,000 foot laterals. Is that inclusive of savings that would come from two well pads or in terms of the economics that you now provide are those still for single well pads?

So Ron that's a good average of kind of single wells and two well pads. We really haven't done too many two well pads to-date. They really have a good historical ground but most everything we are going to be doing going forward is going to on two well pads. So I think we have actually got the potential in there to probably show you few extra dollars off of what we have presented here.

Great. Thank you.

Thank you. And our next question comes from David Epstein from Cowen, your line is now open.

Hi folks. You guys said you don't want to give too much about the playbook of the refi and that's fine. I am not looking to price, but I just want to make sure I heard something correctly. Did you say that no part of that is changing like the conversion ratio on the second liens?

Yes that's correct. Obviously, the bonds are what they are and the authorizations are what they are. So the plan is I think with the sale proceeds to look at all the tools we have in hand and we think mostly likely and that’s the stock really causes conversions those bonds probably will be called diversified, converted. That's a good possibility.

Okay and on Grantham, I think you guys said higher water production and limited capacity limited the IP to 20 million cubic feet a day. Is that strictly in IP? How much does it hit like your – will it catch up overtime it will the EURs look any closure to sort of your type curve?

Yes. So this is Dan. I think time will tell, we don’t have that well in production for probably couple of months now and two and half months. And typically the wells, all of these wells with the newer larger frac jobs we do flow back a lot of water obviously in the early timeframe and so when we go to these longer laterals we had to flow them little bit longer just even basically every well form longer to achieve an IP. This well is an area where we did have just a little bit higher average water production and with the larger frac job that we put on it we got a lot larger water rate down initially and it just restricted being able to get an IP in that early timeframe and of course as it keeps flowing the well you lose a little bit of flowing pressure. It kind of diminishes being able to get the normal IP that you normally would. We are definitely limited with being able to get rid of the water off the location that was also a fact we just can't find enough trucks to basically to dispose of it. So we had to cut right back little bit.

Okay. Thank you.

Thank you. [Operator Instruction] And our next question comes from Joshua Gale from Nomura Securities. Your line is now open.

Hey guys thanks for sliding me in the queue. I appreciate all that color on the location count it’s immensely helpful. I just had a question about the wells, if I take the net well count and the CapEx budget for 2018 and implying about 10.5 million on average but I know that two-thirds of the rig activities is going to be focusing areas where there is a lot of 10,000 foot laterals. So the well cost in slide 23 is that maybe a conservative estimate by drilling two well pads and completing in batches of two or four there is potentially some savings baked into that operating plan for 2018?

This is Dan. So there is, the prices that we have here the cost are really kind of -- really some single well pads and two well pads. With exclusive basically for the remainder of this year and into next year with most being all two wells pad there is some potential there to probably save off a little bit of cost from what the numbers are here. But I’ll also caution that we it also depends on what our service cost are going to be next year. We think we have kind of gotten past most of the really rapid increase in cost we had this year and hopefully this year and the next year we are looking at something a little bit kind of level from here going forward just talking to our service providers, we are expecting the cost to kind of level out where we are at.

Alright, thanks. And then just if I could slide in one more, the commentary in the press release about funding with operating cash flow I know you have a plan to do something in March of next year with the first lien notes but is that like a status quo assumption and does that basically take into account the interest that you pay on the first lien notes for the year?

Yes that's a status quo type of assumption. We are not assuming a different capital structure for this basic drilling program that we are putting in. I think post refinance if we have a lot lower interest cost that we could, we probably would have a larger capital program, drive more growth. But that's a status quo assumption that the capital structure stays the same and we always budget to pay the first lane interest in cash. So that's also comes out of the cash flow also.

Right. So I know you didn't formally guide but if I take 70 million of cash interest and $170 million budget subject to gas prices that implies $240 million in EBITDA is that fair?

That is pretty fair.

Great, thanks a lot.

Thank you. At this time I am showing no further questions. I will now like to turn the call back over to Jay Allison, CEO for closing remarks.

All right Jiji, going back to Mike Kelly who is from Houston, which is home of the Astros and his word playbook, I would tell you that Astros won the world series of baseball last night. When they did that they gave us the playbook so let's just hope we can implement the playbook we have that have given us as well as they do. If we do they will do what they did which is be really successful. That's it. Thank you Jiji.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may now disconnect. Have a great day.