Comstock Resources, Inc. (CRK) Q4 2017 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the Q4 2017 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions] As a reminder, this conference call maybe recorded. I would now like to introduce your host for today’s conference, Mr. Jay Allison, CEO. Sir, you may begin.

Alright. And again, thank you Crystal and thank you for everyone who is participating this morning on our fourth quarter and year end conference call for 2017. Welcome to the Comstock Resources’ fourth 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 will find a presentation titled Fourth Quarter 2017 Results. I am Jay Allison, Chief Executive Officer of Comstock and with me is Roland Burns, our President and Chief Financial Officer and Dan Harrison, our Vice President of Operations. During this call, we will discuss our fourth quarter and full year operating and financial results as well as discuss our outlook for 2018. If you turn over to Slide 2, please refer to Slide 2 and our presentation 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. Slide 3, our 2017 achievements. It was 3 years ago this month that we announced a business plan to develop our Haynesville, Bossier acreage. During those 3 years, we have drilled approximately 50 gross or 33 net Haynesville, Bossier wells. We have increased our drill site locations. We have brought in an incredible JV partner with USG. We have expanded our Tier 1 footprint and have a deep inventory of locations that have very attractive of ours at current natural gas prices. I would note that it has been a very long journey, but our results have exceeded our expectations every year and we continue to get stronger quarterly. As we announced in the third quarter 2017 conference call, we are aggressively putting all the components in place to recap Comstock by March or April depending upon market conditions. Our commitment has not changed any, because we know our expensive debt is restricting our growth. So, our balance sheet has to be de-levered. On Slide 3, we outlined the 2017 achievements. Against a backdrop of challenging industry, we accomplished many of our goals for the year. Our primary goal was to grow the company’s operating cash flow and EBITDAX to support our debt level. We might break great progress toward this goal in 2017. It all starts with production though. The Haynesville shale wells we drilled were up to the challenges I drove by 46% growth in our natural gas production, pro forma for divestitures we made in 2016. We finished strong in the fourth quarter, where natural gas production was up 90% over the fourth quarter of 2016. The higher natural gas production calls our 2017 sales to grow by 49% and our EBITDAX increased by 103% over 2016. Cash flow from operations for the year grew to $112 million from a deficit of $8 million in 2016. Our Haynesville drilling program turned in consistently strong results as we enhanced our completion design and achieved 36% higher initial production rates. In 2017, we drilled 30 successful wells, which had an average per well IP rate of 25 million per day. The drilling program allowed us to grow our proved reserve base by 27% and achieve a very low all-in finding cost at $0.54 per Mcf. The joint venture we have with USG has allowed – has continued to grow our inventory of Haynesville and Bossier Shale locations in 2017 which sit at over 800 today. The first two wells report a lot on some of their acreage generated by the joint venture look to be outstanding wells, so that will be right to 27 million per day. As we discussed on our last conference call, we are very focused on improving our balance sheet and are working hard with our advisors to position the company to refinance our expensive debt as soon as practical this year which again could be as early as March or April depending upon market conditions. Our plans are still to refinance all of our secured notes with a combination of proceeds from the sale of our Eagle Ford properties and their credit facility and their bonds and some equity. All their components were tied together which should fall into place when we are able to complete the Eagle Ford sale. We are not in a position to announce the sale today as we are working with several potential acquirers who are working to solidify their financing are still completing their valuation work. We were very encouraged by the first round of indications of value we received that are now focused on working with higher bidders to find the best deal for Comstock. We entered 2017 with total liquidity of $186 million which is more than adequate for us to carry out our planed 2018 drilling program. I will now hand it to Roland Burns to go with financial results we announced today. Roland?

Thanks Jay. On Slide 4, we showed the growth in our natural gas production being generated by our Haynesville Shale drilling program. In the fourth quarter our natural gas production averaged 241 million per day, up 90% from pro forma 2016 fourth quarter production and was also up 11% from the third quarter of 2017. With the drilling program in 2018 similar to 2017’s program, we estimate that 2018’s natural gas production should average between 250 million to 270 million today. On Slide 5, we outlined the additions to our hedge position since we last reported. We had 99 million per day of our natural gas production hedged in the fourth quarter at $3.38 per Mcf. For the first quarter of this year, we have 42 million a day hedged at $3.26. And for the remainder of 2018, we have 60 million a day hedged at $3. We do plan to add more hedges to get closer to our 60% goal of production. Slide 6 recaps what production we had to shut-in for the quarter. The fourth quarter was fairly quiet and our shut-in gas production only average 4.5 million per day. And the shut-ins were mostly due to necessary shut-ins for offset frac activity either for our operations or for activities that offset operators. Our oil production in the fourth quarter was more negatively impacted by shut-ins as 131 barrels per day were shut-in. These shut-ins were all due to offset frac activities from nearby operators as activity in the Eagle Ford has picked up. Slide 7 shows our producing costs continue to improve quarter-over-quarter as our lower cost Haynesville Shale property production continues to grow up. Operating costs have improved in the fourth quarter to $0.68 per Mcfe as compared to $1.48 all the way back in 2014 and $1.10 in 2016. With much of the production from the new wells in the Haynesville Shale exempt from production taxes for their first several years, our production taxes averaged $0.07 in the quarter as compared to $0.36 back in 2014 and $0.08 last year. Our total field level cost in the quarter came in at $0.39, so big improvements with $0.97 in 2015 and $0.76 last year. Then our depreciation, depletion and amortization per Mcfe produced has come down fairly dramatically, it was $1.29 per Mcfe this quarter as compared to $5.74 in 2014 and $2.26 last year. With all that improvement is due to very low finding cost of the Haynesville Shale wells and the growth in the Haynesville Shale production. If you exclude the Eagle Ford operations which we – as we are saying is held for sale on our fourth quarter balance sheet, our total operating costs per Mcfe would have been $0.53 this quarter and our DD&A per Mcfe would have been $1.27. For most of the – for 2 of the 3 months in the fourth quarter, since our Eagle Ford properties were held for sale, they were not included in DD&A. Our future cost structure after we completed the sale of the Eagle Ford and after we completed the refinancing of our expensive data, we will be very competitive in the industry. On Slide 8, we summarized the fourth quarter and financial results. The growth in gas production, improved prices and lower operating costs per unit of production continue to drive the improvements to our sales and cash flow. Our natural gas production increased 81% and natural gas prices increased by 3%. As a result, the oil and gas sales this quarter were up 59% to $77 million from the fourth quarter of 2016. Our EBITDAX was up 106% to $56 million and our operating cash flow came in at $38 million, which is up 309% from the fourth quarter of 2016. On the cost side, our lifting costs in aggregate were up 14%, but way down on a unit production basis since production increased by 67% in the quarter. Our G&A cost in the quarter were down 18% and then our depreciation, depletion and amortization was up only 5% despite the 67% increase in production. For the fourth quarter, we did report a net loss of $42 million or $2.86 per share, but this loss included several unusual items, including an impairment of $44 million, $10.9 million of non-cash interest expense associated with the discounts recognized and the cost incurred on the debt exchange that we completed last year, an unrealized loss on derivative financial instruments of $1.9 million and then a $19.1 million income tax benefit due to the changes in the U.S. federal income tax law. If you exclude these items, the net loss for the quarter would have been about $0.31 per share. Slide 9 recaps the financial results for the full year 2017. Our natural gas production grew 37% and oil and gas prices increased by 28%. Oil and gas sales for 2017 were up 49% to $265 million and our EBITDAX came in at – was up over 103% to $184 million. Operating cash flow for the year were $112 million, which was a substantial improvement from the cash flow deficit of $8 million that we had for 2016. Producing costs were also down considerably year-over-year, which also contributed to the improved financial results in combination with the growth in production. Lifting costs were down 11% and our DD&A was down 13%. Our G&A cost year-over-year were up 9%. Overall, we reported a loss of $111 million for 2017 or $7.61 per share. The unusual items in the loss included an unrealized gain from derivative financial instruments of $7.3 million, impairments in loss on sales of property at $45 million, $35.7 million of non-cash interest expense, which is associated with the discounts recognized the cost incurred on the debt exchange, I mean, really represents a reversal of the large gain that we booked last year on the exchange, then the last item of course with the $19.1 million benefit due to the new federal income tax law. Without these items, the net loss for the year would have been $3.90 per share. On Slide 10, we covered our balance sheet at the end of 2017. We had $61 million of cash on hand and $1.195 million of total debt outstanding. If you include the un-drawn credit facility to cash on hand and the available pay-in-kind interest that we have on our first lien bonds, which we have not used, our total liquidity is at $186 million that we are taking into 2018. As Jay covered earlier, the potential sale of our Eagle Ford shale properties should allow us retire in part and refinance in part our first and second lien notes. The ingredients for the refinance includes the sales proceeds from the asset sale combined with our new secured credit facility and unsecured bonds and most likely some equity, so there are a lot of moving parts to pull together to remake our balance sheet. I assure you we are doing everything we can to get this accomplished as soon as practical and hope to report back to you soon as we put some of these pieces into place. On Slide 11, we recapped the growth in our proved reserve base in 2017. We grew our proved reserves from 916 Bcfe to 1.2 Tcfe in 2017, primarily from the reserve additions from our Haynesville Shale drilling program. The SEC prices used to determine proved reserves improved in 2017 to $48.17 per barrel for oil and $2.88 per Mcf for natural gas as compared to 2016 prices of $37.62 oil and $2.29 for gas. These higher prices caused small upward revision of about 27 Bcfe. But the big changes in the reserves were driven by the reserve additions primarily coming from the Haynesville Shale program, which were 307 Bcfe. At the end of 2016 our proved reserves included 52 net proved undeveloped locations related to our Haynesville shale properties. At the end of 2017, the proved reserves included 61 net proved undeveloped locations. So with an inventory of over 800 drilling locations you can see there are many more locations to include in our proved reserves in the future. Our all-in finding costs for 2017 came in at a very attractive $0.54 per Mcfe. Slide 12, recaps our capital spending in 2017. We spent $179 million in 2017 drilling 30 wells or 15.7 net to our interest. 22 or 14.4 net were Haynesville wells and 7 or 1.3 net were Bossier Shale wells. And the remaining well was a smaller interest in the Cotton Valley well. On Slide 13, we outlined our 2018 drilling program using the three operated rigs that we are currently running. As we announced earlier, we expect to have – to utilize two of the rigs in connection with drilling wells under our joint development program with USG and that we are using one rig primarily to drill our legacy acreage in the Haynesville Shale. So currently we plan to drill about 31 wells or 12.4 net wells in 2018 for an estimated capital outlay of about $133 million. We are also budgeting $18 million to complete wells that we drilled in 2017 that are being completed here in the first quarter and we have five refracs budgeted for 2018 for $16 million. Depending on industry conditions, we can increase or decrease this budget. And so now I am going to turn it over to Dan, so he can bring you up to-date on what’s our most recent results in our Haynesville Shale drilling program.

Hey. Thanks Ronald and good morning out there and everyone. I will start off here on Slide 14 which you have all seen before highlights our 68,000 net acres in the Haynesville and in the mid-Bossier Shale play in North Louisiana and East Texas. We operate most of the net acreage position. We had an average working interest of 79% across the 88,000 total acres we have an interest in. The average net revenue interest across our acreage is 81%. In 2017, we drilled the total of 29 Haynesville or mid-Bossier Wells on our acreage were 15.7 net to our interest. By continuing with our existing three rig programs, we tentatively plan to drill a similar number of wells on our acreage this year. Flip over to next slide. On Slide 15, you will see an updated overview of our horizontal well inventory. In 2017, our average operated lateral length completion was 7,900 feet. In 2018, we expect this number to increase to an average length of 8,400 feet or 6% increase over 2017 levels. The longer laterals coupled with pad drilling and our latest generation high intensity frac designs continue to deliver strong returns. The location of the Haynesville near Henry Hub combined with our competitive gathering and treating contracts gives us a premium natural gas market for our Haynesville production. We are currently working towards additional choice with offset operators to further enhance our inventory of long laterals. At this time our inventory of 10,000 foot laterals now stands at 161 in the Haynesville and 182 in the Bossier. Our 7,500 foot lateral inventory stands at 95 in the Haynesville and 88 in the Bossier. And our single section 4,500 foot lateral inventory is comprised of 198 in the Haynesville and 118 in the Bossier. In total this gives us 842 locations in the Haynesville of Bossier shale with 82% of these locations will be operated by us. In addition to our Haynesville and Bossier well locations we also have 285 future horizontal Cotton Valley locations to drill. We also have a very nice inventory of refrac opportunities across our 175 older vintage Haynesville producers of which 117 of these are operated by us. On Slide 16, this is slightly an updated comparison our Gen 1 versus Gen 2 completion IP results per 1,000 feet of completed lateral. As you can see 19 Gen 2 completions continued to deliver superior well results as compared to the 13 Gen 1 completions. Our Gen1 design used 2,800 pounds per foot of sand that was 250 foot of stage length comprised the five perf clusters at 30 foot spacing. Our Gen 2 design uses 3,800 pounds per foot of sand applied on over 150 foot stage length which is five perf clusters at 30 foot spacing. While the Gen 1 wells delivered 3.3 million per a 1,000 feet of lateral of 19 Gen 2 wells have delivered us an average of 4.4 million cubic feet per day IP per 1,000 feet of lateral or 36% up-tick in performance. Slide 17, you will recognize this shows 34 of the 36 Haynesville wells plus the two Bossier wells that we have completed since the beginning of our program in 2015. With two remaining Haynesville wells are located further north in the play, we will talk about those a little bit more on the next slide. The wells with the red color of the 13 Gen 1 wells drilled in 2015 and through the first three quarters of 2016. The well callouts represented 20 of the 23 Gen 2 wells we have drilled fast late 2016. Since our last conference call, we have completed an additional seven wells, six Haynesville wells plus one Bossier well. And also had the six most recent Haynesville completions were all drilled of this two well pads. The average initial production rate of these wells is 23.5 million cubic feet per day. Five of the seven new completions are highlighted on this slide. On our 21 #2 and #3 wells were both drilled to an average total vertical depth of 11,950 feet with 4,550 foot laterals. The initial production rate for both wells was 30 million cubic feet per day. The BSNC LA 18-7 #1 well was drilled to the Bossier at a vertical depth of 11,218 feet with 7,489 foot completed lateral. Its initial production rate was 21 million cubic feet per day. Today’s production from the newest Bossier well is tracked virtually the same as our initial very successful Jordan 16-21 #1 well that’s completed in late 2015. The Bogle 36-1 #1 and #2 wells were drill to an average total vertical depth of 11,056 feet. The #1 well was completed with a 7,818 foot lateral and tested with and oil production rate of 16 million per day. The #2 well was [indiscernible] with a 5,228 foot completed lateral and was tested with an initial rate of 14 million cubic feet per day. Both wells were choke-back initially due to higher than expected initial water rates and other operational constraints. As of today we are fracing four wells that have an additional of five wells in various stages of completion. We also have two wells waiting on completion. On Slide 18, [indiscernible] jointly development program with USG, the initial activities of the joint development program has been focused primarily in Caddo Parish, Louisiana work to-date. USG has acquired 6,300 net acres targeting the Haynesville Shale and on our Comstock and USG to drill 34 extended lateral wells. We have six 1,000 foot lateral wells in the acreage so far and we are currently drilling the seventh and eight wells. Since our last update we have completed the first two Haynesville wells on this acreage as part of the two well pad. The Hunter 28-21 #1 and #2 wells were drilled to an average total vertical depth of 11,135 feet and averaged 9,218 foot completed laterals. Both wells were tested with an initial production rate of 27 million cubic feet per day. We are participating with the 25% working interest in these wells and plan to increase our working interest to 40% starting with the 13th well on this acreage. USG is also participating in four of our wells being drilled targeting the Bossier formation in the DeSoto and Sabine Parish in Louisiana. As mentioned on the previous call, the first well in this four well Bossier program the BSMC LA 18-7 #1 was completed with the 7,489 foot lateral had an initial production test of 21 million cubic feet per day. The remaining three Bossier wells are in various stages of drilling and completion. USG is also participating in the drilling program on approximately 5,800 net acres of Harrison County, Texas that will target the Haynesville Shale. We are currently drilling our first two well pad in this area and expect to finish completing the wells about mid-year. Again on Slide 19, we show the same-well performance that I just presented on the previous slide for all of our Gen 1 and Gen 2 completions. The well performance to-date on this slide have been normalized to show the initial production rates per thousand feet of completed laterals that will illustrate the superior results of the Gen 2 wells versus the Gen 1 wells. Let’s move on to Slide 20, this shows the latest update to highlight our Haynesville and Bossier wells with sufficient production and they are still performing against our base 7,500 foot type curve. The red curve represents the average of our 12 Gen 1 wells which were drilled and completed in 2015 and early 2016. These wells had a significant amount of production history and continued to perform above our type curve. The purple curve represents the average of 10 Gen 2 wells which continued to outperform the Gen 1 wells so far. The light blue curve represents the average of our eight shorter lateral wells which were completed using the Gen 2 design. Our shorter lateral wells continue to exceed our expectations and continue to perform close to our 7,500 foot type curve while producing from the laterals over 40% shorter in length. These 4,500 foot laterals being coupled with pad drilling in our latest Gen 2 fracs are still delivering very attractive returns and are very important part of our portfolio. And last, but not least is the green curve which represents our two Bossier wells which were producing virtually the same as each other today. Our initial Bossier well, the Jordan 16-21 #1 well continues to outperform our average Gen 1 Haynesville well. On Slide 21, we have adjusted the data presented on the previous slide reflect production per 1,000 feet of completed lateral. The red curve again represents the average of our 12 Gen 1 wells drilled in 2015 and early 2016. The average length for these wells was 7,194 feet. The dark blue curve represents the average of our 18 Gen 2 wells that have been drilled since late 2016. These wells have an average lateral length of 6,438 feet. The green curve again represents the two Bossier wells have been completed – the [Technical Difficulty] for these two Bossier wells was 7,460 feet. As you can see the Gen 2 wells are continuing to outperform the Gen 1 wells longer term. Slide 22, this is our simple illustration of how we can approach refracing side [indiscernible] wells the sand is what have already been successfully bought by other operators in the play. As opposed to the earlier version of refracking, there is a lot of massive volume diverted to be bought into the original completion in an attempt to square the refrac out across all the original perf clusters. Lateral refrac totally isolates the original completion utilizing a 3.5 inch liner that is run inside the original case cemented in place. This allows the well to then be completed again using the [indiscernible 0447] plug and perf method and this time using the latest high intensity plug deign, tighter cluster spacing and much higher sand wagons volumes. This new completion allows access to reserves that would have otherwise been left behind or stranded, wider cluster spacing in undersized fracs. We are currently preparing to refrac our first Haynesville Shale well by early April and have results we report on our next update. Slide 23 provides the summary of the underlying assumptions and economics for the different lateral length cases and also the refrac case using our latest Gen 2 frac design and run at NYMEX gas prices of $2 to $3.50. As you can see at a $2.50 flat gas price was generating a minimum 34% rate of return on a 4,500 foot laterals while increasing to a 47% rate of return for our 10,000 foot laterals. At a $3 gas price, the rate of return increases to 60% for the 4,500 foot laterals and up to 75% for the 10,000 foot laterals. For our 2018 Haynesville, Bossier shale program, we are planning to drill 28 to 30 operated wells. Over 80% of these wells are planned to be drilled at 10,000 foot laterals and this is important with the exception of only 2 wells every operated well we plan to drill on 2018 will be from a multi-well pad. In addition to utilizing multi-well pads, we are diligently working to drive down well costs wherever possible through the use of locally sourced sand and other means. All these measures employed together, our latest Gen 2 frac design for longer laterals, multi-well pads and additional cost reductions will generate strong returns and cash flow into the future. That is quick summary of the operations. And with that, I will turn it back over to Jay.

Alright, Dan. I love Slide 23. Thank you for your presentation, Roland. Thanks for the excellent reports. For the quarter and the full year 2017, if we go to Slide 24, which is our 2018 outlook, our high return Haynesville shale assets continue to provide us the means of profitable growth production and cash flow in 2018. Our enhanced completion design as Dan has mentioned has transformed the Haynesville shale into one of North America’s highest return natural gas basis and our acreage position gives us over 800 future drilling locations. Our drilling activity planned for the year will allow us to grow natural gas production by 30%. The production increase will cause our EBITDAX and cash flow to continue to grow. Our already low cost structure has continued to improve with further growth in our Haynesville shale production. In 2017, we were able to reduce our lifting cost per Mcfe by 31% and our DD&A per Mcfe has improved by 32% as compared to 2016. Our balance sheet will 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 support our effort to refinance our secured debt this year. For the rest of the call, we will take questions from the analysts through [indiscernible] company. I would add – all that we would like to do we cannot discuss that Eagle Ford Shale’s process in anymore detail, but we will inform our stakeholders when we have entered into a contract. So with that, Crystal, we will turn it over to you again.

Thank you. [Operator Instructions] And our first question comes from Ron Mills from Johnson Rice & Company. Your line is open.

Good morning. First question would be on Caddo Parish, obviously, first two wells, they seem to be really strong almost approaching productivity rates of the DeSoto Parish wells. Maybe for you Dan, can you discuss how those wells came in versus expectations or especially results versus the – what risk you may have expected as you moved up north versus DeSoto Parish?

Yes, Ron. I mean, we are super excited about those wells. They definitely exceeded expectations I’d say the biggest risk was just the unknown of having a lot of newer vintage wells completed up that far north in the play. And I mean, there was obviously a significant number of radical number, I should say, of older vintage wells in the area that basically led us to believe this would be an area, but you never know so you put one of these fracs on see what you get. I will say the wells were very strong, I mean are basically hanging in there with a very little drop off since we [indiscernible].

Okay. And as we look at the 2018 capital programs, had a curiosity, a little bit larger number of gross wells, a lower number of net wells in the Haynesville, is there also some shift as from North Louisiana, East Texas is as you started to test the Harrison County position?

Ron, this is Roland. This is really not a significant change in the main drivers of the budget. There are some non-operated projects that are firmed out since we reported the third quarter that are in that number, but they are not – there is very small interest. So there is obviously as you get closer drilling the well, you will find exact ownership you have and then sometimes we may change the order of the projects kind of based on what fits the two dedicated frac crews and the three operated wells. But generally I would say there is very little change to the need of the budget that we presented earlier on this one just refinements.

And then last one operationally just on the on the Bossier, obviously that the Black Stone Oil looks a lot like the Jordan well, when you think about the development mode, how does – how do you think the Bossier hits in with the Haynesville, it looks like a little bit lower IP rates, but flatter decline, is that a correct representation in what did the relative economics look between the Bossier and the Haynesville?

Well, the Bossier looks – the Bossier does look just the same as the Jordan well we did in 2015. I will say operationally those wells are coming to slip the two that we have completed historically, a little bit tougher to complete and are tougher to frac, slightly more expensive just to do that and bumps usually so a little bit more to get out all the sand put away. But they did have that flatter production profile which we are really happy to see. And I would say just if you stack one versus the other obviously the Haynesville is the better rock between the two, but no long-term before the Bossier is going to be – will be a big, big value add for the company.

Great, I will let someone else jump and get back in line. Thanks.

Thanks Ron.

Thank you. And our next question comes from Mike Kelly from Seaport Global. Your line is open.

Thanks. Good morning guys.

Hi Mike.

Hey Jay. Great to hear the expectations haven’t changed, it pertains to the balance sheet initiatives and I have just got two questions on this you may [indiscernible] both of these, but we will try anyways, so one would be the $200 million and $300 million range for the Eagle Ford just want to hear if that’s a good number. And then two, just hearing your confidence that everything really should fall in place post the Eagle Ford sale makes me think, but you have got a framework really kind of teed up for how that revolver and a high yield offering would look and wonder if that’s fair – a fair comment and then just any more color on that front? Thanks.

Yes, sure. Mike this is Roland. Yes, I think that’s – I think you summarized it well. I think we are on course and to complete the kind of the refinancing, as you described. I think on that we obviously can’t get into that, but there is still uncertainty over the final sales price. But we are working with several companies to find the very best deal for us and hopefully that will complete soon because it’s a little bit of a gating item it seems like to finalize the others. The range, I mean that – we would probably steer you towards the lower end of the range. But we still think the range is good just based on market feedback at this point. And that’s probably the most in-depth we will go and we know to report back sooner rather than later on a more complete answer to your question.

Yes. And Mike I would add to that, remember it’s the sum of the parks. It is the Eagle Ford sale, the new credit facility, the new bonds and some equity. It’s the sum of that to get our leverage down and to create wealth on a per share basis for our stakeholders.

Yes, I appreciate that and it’s great to hear that range is still in place, so good. And then operationally switching gears here the Caddo Parish, I am sorry the Bogle well results, I wanted go there, you mentioned that operationally some constraints here, maybe some more water, could you just give a little bit more color on these wells and if you expect them to ultimately turn up and look like type curve or better type wells? Thanks.

Thank you. Yes. This is Dan, so the Bogle well is, if you remember our Grantham well based on our last call the Bogle wells were drill down on the very South end of acreage of the same area. We – there are some 3D seismic that indicates there are some faults located South of our acreage. And the south end of the area is in close proximity. We are just seeing a little bit more water on the initial flow rates, but we think these wells are going up still perform quite nicely, definitely be like we have seen the Grantham base since the last quarter. And it just sits with the higher initial waters that we make – when we were in this we are driving the well back, it’s hard to get an IP. And we are also limited by how much water we can halt, especially with the two well pad, we just add excessive amounts of water that we just couldn’t haul off to open up the wells any further.

Got it. I appreciate that color. Thanks guys.

Thank you. Our next question comes from Phillips Johnston from Capital One. Your line is open.

Hi, guys. Thanks. You have mentioned Eagle Ford oil volumes were impacted by shut-ins, I am not sure if you can answer this one, but what should we think about in terms of occurrence sort of normalized run rate of production there?

So this is Dan. We have – there was definitely a big up-tick in activity. I would say most of this was –most of this was the activity that we are seeing around us over in four corners area. We just had a lot of wells shut-in. We don’t expect this to be a continual thing throughout the end of this year. I think they just were there program wells was primarily located right around our acreage. In the fourth quarter, we are not seeing quite as much of that in the first quarter and hopefully it will wind as we get further into ‘18.

Okay. So probably, somewhere close to that sort of 2,300 a day kind of rate or so?

Yes, sir pretty similar.

Okay. And I think the good thing about that although we have had production shut-in it takes you that the activity around our footprint of acreage has increased. So that’s a good thing, so.

Okay. And then Eagle Ford PV10 [ph] I think at year end was $109 million based on SEC pricing, are you able to disclose what that number looks like either based on current strip prices or strip prices kind of as of year end ‘17?

I can that to you later on, we just have don’t have it exactly in front of us.

Okay. Thank you, guys.

Thank you. And our next question comes from Chris Stevens from KeyBanc. Your line is open.

Hi, guys. Nice, well results this quarter. I was just kind of curious how many of these refracs have you, I guess did you complete last year or I guess have you tested any wells with the newer line of refrac design that you show on the presentation?

So this is Dan, what we did not – we did not do any refracs last year. We basically have done the prep work on our first well and will be fracing that well about around the end of March.

Okay. So I guess the – at this point, how should we think about the shape of how these wells are going to decline, I mean you show the IP rate of 12 million a day, are you expecting it to kind of look relatively similar to a newer well just from a lower starting points and I guess just what’s the type curve based on at this point?

So most of this is based on the other results from other operators in the industry, we have seen these IPs that range from say 1.2 to 1.5 the original IPs at the wellhead. And of course just the historical production that we have got on some of those wells is what we have used to build our type curve.

Okay, got it. I guess just in terms of the operating expenses into 2018, we are seeing pretty nice sequential declines throughout 2017, so any guidance on what the unit operating expenses could look like in 2018?

Yes. This is Roland and I think you obviously can take the fourth quarter and eventually without the Eagle Ford kind of numbers in the fourth quarter and take them into 2018 with maybe some slight continued improvements as additional volumes – the additional volumes come with a little lower overall cost than the total company volumes are now so probably not as dramatic of changes, because eventually we get down to kind of the base cost of the new wells, but I think there is still a little bit more improvement to go, but in the fourth quarter, numbers without Eagle Ford are a great kind of starting point maybe with slight improvements later in 2018.

Okay. Appreciate the color. Thanks a lot.

Thank you.

Thank you. Our next question comes from David Beard from Coker Palmer. Your line is open.

Thank you gentlemen and good morning.

Good morning.

A micro and a macro question for you. On the micro front relative to the use of brown sand, could you give us a little more color relative to the service company give you any guarantee of performance and in terms of cost savings you can quantify that and would you think about taking some of that cost savings and increasing your sand loadings on the sand front?

So, this is Dan. We are not looking at increasing our sand loadings with the local sand. We are looking at that primarily as a cost reducer though. We have just started using some locally sourced sand in our Haynesville fracs with the fracs that we got going on as of today. We are looking at about a 50:50 mix between that the white sand right now, because of mainly due to what’s available to us. Starting a little bit into next month, we anticipate having 100% availability of local sand. And the cost savings are definitely – they are fairly significant. As far as performance, we don’t feel like there is going to be any performance degradation due to the local sand. We have to a lot of the other operators that are a little bit ahead of us on how much they have pumped. And none of – I haven’t heard any negative news from other operator scores, anything affecting performance. Now, that’s longer term, I mean, we will have just to wait and see. I mean, that’s the local sand use in the Haynesville obviously has it been around for a real long time.

Good, thanks. And then on the macro question, you just referenced the use of equity couple of times in your comments and I wondered if that referred mostly to the conversion of the second liens or maybe some additional equity would help grease the wheels of refinancing the balance sheet or any color you could give there would be helpful?

Right. We can’t be too specific, but I think either source would be probably what we in addition maybe – but we haven’t really decided the best way to create that additional equity or the amount yet that we would seek to work, because I think for the successful bond operating all that and we really want to target improved leverage from where we have been and so I think the combination of that and the asset sale are key to putting in long-term debt that works really well for the company.

Totally understand. Appreciate the time gentlemen.

Thank you.

Thank you. Our next question comes from Ron Mills from Johnson Rice & Company. Your line is open.

Just a quick follow-up on David’s question, Dan, if you think about the well cost as you presented on Slide 23, the move to local sand, what kind of impact could not have on the well cost versus the range you currently present?

So if we go 100% of local sand on a 10,000 foot well, you are looking at somewhere in the neighborhood of $0.5 million savings per well, which is pretty significant, the frac tell us about, I mean just the frac ticket alone is about 45% of the entire well cost. So, anything you can do to reduce cost layer is impactful, everything else after that or the smaller claims that you are working on, but I think that we have just heard nothing, but good news from the other operators that are using local sand and I just think that’s going to be around the stake.

Okay. And then just sort of housekeeping, Roland, on the cost structure when you breakdown the cost, I know you point to $0.53 of gathering production taxes and lifting costs without the Eagle Ford. What does that $0.53 look like from a breakdown standpoint? I am trying to get a sense as to what you think the – I think the biggest impact is going to be lower LOE going forward, I am trying to get a sense of the breakdown of that cost structure into Eagle Ford?

Sure. I mean, yes, I think the most consistent item is the gathering and transport cost because it’s more variable-based. So, that stays very confident I think if you could see between like third and fourth quarter. We see a little bit of reduction in production taxes and that of course it’s from the $0.07 maybe it comes down $0.01 or $0.02 lower than that as you progressed through ‘18. Now, the balance of it is really whole that’s all the – the balance of the lease operating expense, which because a lot of those numbers – lot of those cost item more fixed in nature than variable, so just the additional volumes kind of drive that down a little bit. So, the magnitude of the change may could be as much as another from fourth quarter of this year to fourth quarter next year you have, if everything goes to plan, we could see another $0.10 plus kind of shaved off that number.

But another way to think about it, that $0.39 LOE if most of the overall cost structure improvement is LOE that $0.39 comes somewhere in the $0.20 to $0.25 range, is that the right way to think about it?

Right. I would think yes, more in the $0.25 range is where we can get to.

Great. Thank you.

Eagle Ford kind of off that as a playing field.

Right. Okay. Thanks.

What you are seeing in the DD&A cost is kind of almost the Eagle Ford already gone, because it’s been moved out of property, it was only really being depreciated that 1 month out of the 3 months in the quarter, so you make those seeing kind of that number almost without the Eagle Ford.

Thank you. And our next question comes from Jeffrey Campbell from Tuohy Brothers. Your line is open.

Good morning.

Hi, Jeff.

Congratulations on the exciting times to come here.

Thank you.

I just want to ask a couple of quick leasing acreage questions. Obviously one as part of the drilling longer laterals, I was just wondering, is there any constructive acreage swapping taking place in the Haynesville similar to what we are seeing in the Permian?

Definitely, we are able to complete one of a trade earlier, I mean earlier in 2017, with offset operator, because it’s the trade is pretty much a win-win if you can lineup the acreage works both productive for both parties, which is often hard to do, but as we have had some new companies come into the Haynesville and start development programs, it’s really those are the rail candidates to do that with, because they can enhance their acreage and we can enhance ours. So, we are constructively engaged with several of them to create more just trading to get – more of the acreage into operated units and maybe create longer multi-section wells versus single section wells.

Right. And I think the implications active basins are going to be a better place to the sort of stuff they happen. So, this is a nice indication of how the health of the Haynesville is appraising?

Sure. I think the difficulty might be that just it’s acreage that’s been dedicated a high,, gathering and transportation arrangement that a poison pill to us for. So that’s the biggest problem in the Haynesville where a lot of it could have been dedicated. Oftentimes maybe those operators can move those obligations to another block. So it just shows you the level of effort that has to go and to make these trades happen there. They are very – a lot of effort goes in both sides to kind of, to create a swap, but when they can be completed, they are very, very beneficial.

That’s good color. And my other question was I know corporate restructuring is the paramount use of cash right now, but I was wondering if you are seeing any interesting opportunities to pick up Bolton acreage and would you be open to acquiring it after - maybe after the Eagle Ford sale.

We are. And I mean we are doing that right now, in fact, that’s why we do have a partner, so we have got some strength even before the Eagle Ford shale.

Yes, even throughout 2017, yes, we were involved in most of that acreage that did trade and we are at the high bidder, but we are actively, the products that we liked we were actively pursuing it under – and again if you have had the luxury of having the USG who is very interested in the same thing. So, it gives us some financial strength, but yes, I think there is – we are excited about being able to more focus on that in 2018, especially after we complete the refinancing, because we do think that there are going to be bolt-on opportunities of all different sizes available.

Okay, great. Appreciate it. Congratulations again.

Thank you.

Thank you. And that does conclude our question-and-answer session for today’s conference. I would now like to turn the conference back over to Jay Allison for any closing remarks.

Alright. Again, thank you Crystal. I always look forward to bringing all of our stakeholders up-to-date and really communicating what the future looks like. I have gone through these slides and as I look at the Caddo Parish and [indiscernible] wells, well performance, I look at the Bossier area and DeSoto Parish and Sabine [indiscernible] and I look at well activity and the performance there, I look at Harrison County and Panola County, looking at [indiscernible] and I look to offset operators that are in that area. I mean really how could you not be excited about the future of Comstock, it was very little bonding, I think we are going to be able to produce incredible performance in the Haynesville, Bossier drilling program and our JV partners Roland mentioned earlier and I did and our USG is perfect for us and for them. It is a true win-win. In the last week and we have met some of you, but we’ve got to speak at a conference in Freeport, which it just Haynesville producers for the most part. There were probably 600 or 700 people in the audience and then when you are in Dallas at a conference and they were probably 80 to 100 people in the audience, but we always say and we said at those conferences that our mandate as management and the board is to protect and on our debt holders and create as much wealth as possible on a per share basis for all equity stakeholders and we always entertain all opportunities that there kind of is out there that can create wealth for our stakeholders, as I look back on it, it was a bold business plan to believe that the Haynesville Bossier drilling program we announced in February 2015, 3 years ago we would be able to pull Comstock out of the deep valley, the E&P sector entered into around Thanksgiving in 2014, which it was a generational downturn that wiped out trillions of dollars of market and reserves to the entire energy sector and calls hundreds of energy sector companies to go away. So, over the past 3 years and especially in 2017, if you listen to Dan and Roland, we believe that the Haynesville Bossier results now allows us the opportunity to recap Comstock by March or April depending upon market conditions as we said, which is our goal and I can share each of you, our stakeholders that we are aggressively putting all the components in place with the goal to make that happen. I want to thank each of you for your time this morning. You can have spend it elsewhere and for your belief in the business plan that was announced 3 years ago, you can be sure that we never grow tired of working to achieve that plan. Thank you for your time.

Ladies and gentlemen, thank you for participating in today’s conference. This does conclude the program and you may all disconnect. Everyone, have a wonderful day.