Comstock Resources Inc (CRK) 2017 Q4 法說會逐字稿

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 may be recorded.

I would now like to introduce your host for today's conference, Mr. Jay Allison, CEO. Sir, you may begin.

All right. And again, thank you, Crystal. And thank you for everyone that's 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 the 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 entitled 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 in our presentation, and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations to be reasonable, there could 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 the 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've increased our drill site locations, we have brought in an incredible JV partner with USG, we've expanded our Tier 1 footprint and have a deep inventory of locations that have very attractive IRRs at current natural gas prices. I know 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 delivered -- delevered.

On Slide 3, we outlined the 2017 achievements. Against the backdrop of a 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've made great, great progress toward this goal in 2017. It all starts with production, though. The Haynesville shale wells we drilled were up to the challenge as they drove a 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 caused 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 very low all-in finding costs of $0.54 per Mcf.

The joint venture we have with USG has allowed us to continue to grow our inventory of Haynesville and Bossier shale locations in 2017, which sit at over 800 today. The first 2 wells we've put online on some of the new acreage generated by the joint venture looked to be outstanding wells with IP rates of 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 advisers 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, a new credit facility, new bonds and some equity. All the components are tied together but 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 or are working to solidify their financing, or are still completing their valuation work. We were very encouraged by the first round of indications of value we received and are now focused on working with the higher bidders to find the best deal for Comstock.

We ended 2017 with total liquidity of $186 million, which is more than adequate for us to carry out our planned 2018 drilling program.

I will now have Roland Burns go over the financial results we announced today. Roland?

Thanks, Jay. On Slide 4, we show 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 of 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 per day.

On Slide 5, we outline 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 shut in for the quarter. The fourth quarter was fairly quiet, and our shut-in gas production only averaged 4.5 million per day. And this -- the shut-ins were mostly due to necessary shut-ins for offset frac activity, either for our operations or for activity by 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 activity from nearby operators as activity in the Eagle Ford has picked up.

Slide 7 shows how our producing costs continue to improve quarter-over-quarter as our lower-cost Haynesville shale property production continues to grow. 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 costs in the quarter came in at $0.39, so big improvement for the $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. 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 are saying is held for sale in our fourth quarter -- on our fourth quarter balance sheet, our total operating cost 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 of 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 complete the sale of Eagle Ford and we -- and after we complete the refinancing of our expensive debt, will be very competitive in the industry.

On Slide 8, we summarized the fourth quarter financial results. The growth in gas production, improved prices and lower operating cost 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 costs side, our lifting costs in aggregate were up 14%, but wind down on a unit production basis since production increased by 67% in the quarter.

Our G&A costs 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 charge of $44 million, $10.9 million of noncash interest expense associated with the discounts recognized and the costs incurred on the debt exchange that we completed last year and 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 was $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 costs 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 derivatives financial instruments of $7.3 million; impairment and loss on sales of property of $45 million; $35.7 million of noncash interest expense, which was associated with the discounts recognized and the costs incurred on the debt exchange and really represents a reversal of the large gain that we booked last year on the exchange; and then the last item, of course, was 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 cover our balance sheet at the end of 2017. We had $61 million of cash on hand and $1,195,000,000 of total debt outstanding. If we include the undrawn credit facility to the 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're taking into 2018.

As Jay covered earlier, the potential sale of our Eagle Ford Shale properties should allow us to retire in part and refinance in part our first and second lien notes. The ingredients for the refinance include the sales proceeds from the asset sale, combined with a 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're 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 recap 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 $48.71 per barrel for oil and $2.88 per Mcf for natural gas, as compared to the 2016 prices of $37.62 for oil and $2.29 for gas. These higher prices caused small upward revisions 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 small interest in the Cotton Valley well.

On Slide 13, we outlined our 2018 drilling program using the 3 operated rigs that we're currently running. As we announced earlier, we expect to have -- to utilize 2 of the rigs in connection with the drilling wells under our joint development program with USG, and that we're using 1 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 estimated capital outline of about $133 million. We also are budgeting $18 million to complete wells that we drilled in 2017 that are being completed here in the first quarter, and we have 5 refracs budgeted for 2018 for $16 million. Depending on industry conditions, we can increase or decrease this budget.

And so now, I'm 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, Roland. Good morning out there to everyone. I'll start off here on Slide 14, which you've all seen before, highlights our 68,000 net acres in the Haynesville and the Mid-Bossier Shale play in North Louisiana and East Texas. We operate most of the net acreage position at an average working interest of 79% across the 88,000 gross acres we have an interest in. The average net revenue interest across our acreage is 81%.

In 2017, we drilled a total of 29 Haynesville and Mid-Bossier wells on our acreage or 15.7 net to our interest. By continuing with our existing 3-rig program, we tentatively plan to drill a similar number of wells on our acreage this year.

Flip over to the next slide, on Slide 15, you'll 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 a 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're currently working towards additional choice of 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 with 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 then 118 in the Bossier. In total, this gives us 842 locations in the Haynesville and Bossier shale, and 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 were operated by us.

On Slide 16, just to show you an updated comparison of our Gen I versus the Gen II completion IP results for 1,000 feet of completed lateral. As you can see, the 19 Gen II completions continue to deliver superior well results as compared to the 13 Gen I completions.

Our Gen I design used 2,800 pounds per foot of sand over a 250 foot stage length comprised of 5 perf clusters at 50 foot spaces. Our Gen II design uses 3,800 pounds per foot of sand applied over 150 foot stage length, which is 5 perf clusters at 30 foot spacing. While the older Gen I wells delivered 3.3 million per 1,000 feet of lateral, our 19 Gen II wells had delivered us an average of 4.4 million cubic feet per day IP per 1,000 feet of lateral or a 36% uptick in performance.

Slide 17, you'll recognize, this shows 34 of the 36 Haynesville wells, plus the 2 Bossier wells that we have completed since the beginning of our program in 2015. The 2 remaining Haynesville wells are located further north in the play, and we will talk about those a little bit more on the next slide.

The wells with the red callouts were the 13 Gen I wells drilled in 2015 and through the first 3 quarters of 2016. The gold callouts represent the 20 of the 22 Gen II wells we have drilled since late 2016.

Since our last conference call, we have completed an additional 7 wells: 6 Haynesville wells, plus 1 Bossier well. I'll also add that these 6 most recent Haynesville completions were all drilled as 2-well pads. The average initial production rate of these wells was 23.5 million cubic feet per day. 5 of the 7 new completions are highlighted on this slide.

Derrick 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 BSMC LA 18-7 #1 well was drilled to the Bossier at a vertical depth of 11,219 feet with a 7,489 foot completed lateral. Its initial production rate was 21 million cubic feet per day.

Today's production from these newest Bossier wells track virtually the same as our initial very successful Jordan 16-21 #1 well that was completed in late 2015.

The Bogle 36-1 #1 and #2 wells were drilled to an average total vertical depth of 11,056 feet. The #1 well was completed with a 7,818 foot lateral and tested with an initial production rate of 16 million per day. The #2 well is completed with a 5,228 foot completed lateral and tested with an initial rate of 14 million cubic feet per day. Both wells were choked back initially due to higher-than-expected initial water rates and other operational constraints.

As of today, we are fracking 4 wells and have an additional 5 wells at various stages of completion. We also have 2 wells that are waiting on completion.

On Slide 18, this outlines our joint development program with USG. The initial activities of the joint development program have been focused primarily in Caddo Parish, Louisiana, where to date, USG has acquired 6,300 net acres, targeting the Haynesville shale, allowing Comstock and USG to drill 34 extended lateral wells.

We have drilled 6 10,000 foot lateral wells in the acreage so far, and we are currently drilling the 7th and 8th wells. Since our last update, we have completed the first 2 Haynesville wells on this acreage as part of the 2-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're participating with a 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 4 of our wells being drilled targeting the Bossier formation in the DeSoto and Sabine Parish, Louisiana.

As mentioned on the previous slide, the first well in this 4-well Bossier program, the BMSC LA 18-7 #1 was completed with a 7,489 foot lateral and had an initial production rate -- production test of 21 million cubic feet per day. The remaining 3 bossier wells are in various stages of drilling completion.

USG is also participating in the drilling program on approximately 5,800 net acres in Harrison County, Texas that will target the Haynesville shale. We are currently drilling our first 2-well pad in this area and expect to finish completing the wells by midyear.

Again, on Slide 19, we show the same well performance to date as presented on the previous slide for all of our Gen I and Gen II completions. The well performance to date on this slide had been normalized to show the initial production rates per 1,000 feet of completed laterals to better illustrate the superior results of the Gen II wells versus the Gen I wells.

Looking over on Slide 20, this shows the latest update to how our Haynesville and Bossier wells with sufficient production history are performing against our base 7,500 foot type curve. The red curve represents the average of our 12 Gen I wells, which were drilled and completed in 2015 and early 2016. These wells have a significant amount of production history and continue to perform above our type curve. The purple curve represents the average of our Gen II wells, which continue to outperform the Gen I wells so far. The light blue curve represents the average of our 8 shorter lateral wells, which were completed using the Gen II design.

Our short lateral wells continue to exceed our expectations and continue to perform close to our 7,500 foot type curve while producing from a lateral that is 40% shorter in length. These 4,500 foot laterals, coupled with pad drilling and our latest Gen II frac design, still deliver very attractive returns and are very important part of our portfolio.

Last but not least is the green curve, which represents our 2 Bossier wells, which have produced on virtually the same as each other to date. Our initial Bossier well, the Jordan 16-21 #1 well, continues to outperform our average Gen I Haynesville well.

On Slide 21, we have adjusted the data presented on previous slide to reflect production per 1,000 feet of completed lateral. The red curve again represents the average of our 12 Gen I wells drilled in 2015 and early 2016. The average lengths for these wells were 7,194 feet. The dark blue curve represents the average of our 18 Gen II 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 2 Bossier wells that have been completed. The average length for these 2 Bossier wells is 7,460 feet. As you can see, the Gen II wells are continuing to outperform the Gen I wells longer term.

Slide 22. This is a simple illustration of how we plan to approach refracking of some our older vintage wells the same as what has already been successfully done by other operators in the play. As opposed to the earlier version of refracking which relied on a massive volume of diverter to be pumped into the original completion in attempt to refac out across all the original perf clusters, the liner refrac totally isolates the original completion, utilizing a 3.5 inch liner that is run inside the original casing and cemented in place. This allows the well to then be completed again using the tried and true plug and perf method and this time, using the latest high-intensity frac design, tighter cluster spacing and much higher sand volumes. This new completion allows access to reserves that would have otherwise been left behind or stranded due to wider cluster spacing in undersized fracs. We are currently preparing to refrac our first Haynesville shale well by early April and have results to report over our next update.

Slide 23 provides a summary of the underlying assumptions and economics for the different lateral length cases and also the refrac case using our latest Gen II frac design and we run at NYMEX gas prices of $2 to $3.50. As you can see, at the $2.50 flat gas price, it was generating a minimum 34% rate of return on our 4,500-foot laterals while increasing to a 47% rate of return for our 10,000-foot laterals. At the $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 as 10,000-foot laterals. And just as important, with the exception of only 2 wells, every operated well we plan to drill in 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, such as through the use of locally sourced sand and other means. All of these measures employed together, our latest Gen II frac design, longer laterals, multi-well pads and additional cost reductions will generate strong returns and cash flow into the future.

That is the quick summary of the operations. And with that, I will turn this back over to Jay.

All right, Dan. I love Slide 23. Thank you for your presentation. Roland, thanks for the excellent reports for the fourth 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 basins. 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 costs 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'll take questions from the analysts who follow the company. I would add, although we'd like to, we cannot discuss the Eagle Ford sales process in any more detail, but we'll inform our stakeholders when we have entered into a contract.

So with that, Crystal, we'll turn it over to you again.

(Operator Instructions) And our first question comes from Ron Mills from Johnson Rice & Company.

First question would be on Caddo Parish. Obviously, your first 2 wells, they seem to be really strong, almost approaching productivity rates at 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 or outline what risk you may have expected as you move up north versus DeSoto Parish?

Yes. Well -- I mean, we're 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 that far north in the play. And I mean, there is obviously a significant number of -- or adequate number, I should say, of older vintage wells in the area that basically led us to believe this would be a good area. But you'll never know until you put one of these fracs on and see what you see get. I will say the wells were very strong. I mean, they're basically hanging in there with very little drop off since we've IP'd them.

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

Ron, this is Roland. There's really not a significant change in the main drivers of the budget. There are some non-operated projects that have firmed up since we reported the third quarter that are in that number but they're not. They're very small interests. So there's obviously -- as you get closer drilling the well, you'll refine the exact ownership you have. And then sometimes we may change the order of the projects kind of based on what fits the 2 dedicated frac crews and the 3 operated wells. But generally, I'd say there's very little change to the need and the budget that we presented earlier on this one, just refinements.

And then last one, operationally. Just on the Bossier. Obviously, that -- the Blackstone well looks a lot like the Jordan well. When you think about the development mode, how does -- how do you think the Bossier fits in with the Haynesville? It looks like the -- a little bit lower IP rates but flatter decline. Is that a correct representation? And what did the relative economics look between the Bossier and the Haynesville?

Yes. The Bossier looks -- the Bossier does look just the same as the Jordan well we did in 2015. I will say, operationally, those wells -- or -- I mean, just with the 2 that we've completed historically, they're a little bit tougher to complete and tougher to frac. Slightly more expensive to do that, to pump, usually. So a little bit more gels to get all the sand put away. But they do have that flatter production profile, which we're really happy to see. And I'd say, just if you stack one versus the other, obviously, with -- the Haynesville is the better rock between the 2. But long term, we feel the Bossier's going to be a -- will be a big, big value add for the company.

And our next question comes from Mike Kelly from Seaport Global.

Great to hear the expectations haven't changed as it pertains to the balance sheet initiatives. Just got two questions on this. You may combine both of these, but we'll try anyways. So one would be the $200 million to $300 million range for the Eagle Ford. I just want to hear if that's a good number. And then two, yes, just hearing your confidence that everything really should fall into place post the Eagle Ford sale makes me think that you've got a framework really kind of teed up for how the revolver in a high-yield offering would look. I wonder if that's a fair comment by me. And then just any more color on that front.

Sure, Mike. This is Roland. Yes. I think that's -- I think you summarized it well. We think we're on course and -- to complete the kind of the refinancing kind of as you described. I think on the -- that, we obviously can't get into the asset sale. There's still uncertainty over the final sales price, but we're 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 file off the others. The range. I mean, we would probably steer you toward 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 can go in. But we're -- we'd hope that we 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 parts. It is the Eagle Ford sale, the new credit facility, the new bonds and some equity. It's a 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'm sorry, the Bogle well results, I want to go there. You mentioned that operationally there are 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?

Yes. This is Dan. So the Bogle wells. If you remember, our Grantham well based on our last call, the Bogle wells were drilled down at the very south end of the acreage at the same area. We -- there is some 3D seismic that indicates there are some faults located south of our acreage. And the south end of the areas, in close proximity, we're just seeing a little bit more water on the initial flow rates. But we think these wells are going to still perform quite nicely, definitely acting like we've seen the Grantham base since the last quarter. And as -- it just fits with the higher initial waters that we make when we're initially drilling the well back, it's hard to get an IP. And we're also limited by how much water we can hold, especially with the 2-well pad. We just had excessive amounts of water that we just couldn't hold off to open up the wells any further.

Our next question comes from Phillips Johnston from Capital One.

You mentioned the Eagle Ford oil volumes were impacted by shut-ins. I'm not sure if you can answer this one, but what should we think about in terms of a current sort of normalized run rate production there?

So this is Dan. We've -- there was definitely a big uptick in activity. I'd say, most of this was due to -- most of this was the activity that we're seeing around us that's over in our 4 corners' area. We just got 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 -- where their program was, it was primarily located right around our acreage in the fourth quarter. We're not seeing quite as much of that in the first quarter and hopefully, it will wane as we get further into '18.

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

I would say, yes, sir. Pretty similar.

Yes. And I think the good thing about that although we've had production shut-in, it tells you that the activity around our footprint of acreage has increased. So that's a good thing. So..

Okay. And then Eagle Ford PV 10, 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?

Yes. I can get that to you later on. I don't -- it's just that I don't have exactly in front of us.

And our next question comes from Chris Stevens from KeyBanc.

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 liner refrac design that you guys show in the presentation?

So this is Dan. We did not do any refracs last year. We basically have done the prep work on our first well, and we'll be fracking that well in 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 or just from a lower starting point? And I guess, just what's the type curve based on it at this point?

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

Okay. Got it. And I guess, just in terms of the operating expenses into 2018, we've seen some pretty nice sequential declines throughout 2017. Is there any guidance on what the unit operating expenses could look like in 2018?

Yes. This is Roland. 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 in 2018 with maybe some slight continued improvements just as additional volumes. The additional volumes come with a little lower overall costs than in the total company volumes are now. So probably as -- 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 -- the fourth quarter numbers, without Eagle Ford, are a great kind of starting point, maybe with just slight improvements later in 2018.

Our next question comes from David Beard from Coker Palmer.

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

Good. And then on the macro question. You just referenced the use of equity a couple of times in your comments. And I wondered if that referred mostly to the conversions of the second liens or if you have 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. Well, we can't be too specific. But I think either source would be probably what we envisioned maybe. But we haven't really decided the best way to create that additional equity or the amount yet that we, let's say, to work because I think for the -- a successful bond offered and all that and -- we really want to target improved leverage from where we've been. And so I think that the combination of that and the asset sale are key to put in long-term debt that works really well for the company.

Our next question comes from Ron Mills from Johnson Rice & Company.

Just a quick follow-up on David's question. Dan, if you think about the well costs as presented on Slide 23, the move to the local sand. What kind of impact can that have on the well costs versus the range you currently present?

So if we go 100% on local sand on the 10,000-foot well, you're looking at somewhere in the neighborhood of $0.5 million savings per well, which is pretty significant. The frac cost is about -- I mean, just the frac taken along is about 45% of the entire well costs. So anything you could do to reduce costs there is impactful. Everything else after that are the smaller things that you're working on. But I think we've just heard nothing but good news from the other operators that are using using local sand, and I just think that's going to be around to stay.

Okay. And then just a housekeeping, Roland. On the cost structure, when you break down the costs, 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? What I'm trying to get a sense as to what you think the -- I think the biggest impact is going to be a lower LOE going forward. I'm trying to get a sense of the breakdown of that cost structure as to Eagle Ford.

Sure. I mean, yes, the -- I think the most consistent item is the gathering and transport costs because there's more -- it's more variable base. So that stays very constant, I think. If you could see between the -- like third, the fourth quarter. We see a little bit of reduction in production taxes from that, of course, it's -- from the $0.07 maybe it comes in $0.01 or $0.02 lower than that as you progress through '18. So the balance of it is really the whole -- all the balance of the -- this operating expense, which because a lot of those number -- a lot of those costs -- our number are 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, I mean, could be as much as another -- from fourth quarter this year to fourth quarter next year, if everything goes to plan, we could see another 10-plus cents kind of shaved off that number.

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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 it -- yes, more in the 25 cent range is where it can get to. That's the Eagle Ford kind of -- that is the playing field. What you're seeing in the DD&A costs is kind of -- almost the Eagle Ford already gone because it's been moved out of property. It was only really being depreciated, the 1 month out of the 3 months in the quarter. So you're basically seeing kind of a -- yes, that number almost without the Eagle Ford.

And our next question comes from Jeffrey Campbell from Tuohy Brothers.

Congratulations on the exciting times to come there. I just wanted to ask a couple of quick leasing acreage questions. Just 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're seeing in the Permian?

Definitely. We've -- we're able to complete one of -- a trade earlier. I mean, earlier in 2017, with offsite operator because it's -- the trade is pretty much a win-win if you can line up the acreage where it's both productive for both parties, which is often hard to do. But as we've had some new companies come into the Haynesville and start development programs, it's really those are the real candidates to do that with because they can enhance their acreage, and we can enhance ours. So we're 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 implication is active basins are going to be a -- better places sort of stuff to happen. So this a nice indication of how the health of the Haynesville's rising.

Fair enough. I think the difficulty might be the -- just -- it's -- acreage has been dedicated to high -- gathering and transportation arrangements that's 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. They just -- it just shows you the level of effort that has to go in to make these trades happen. They're very -- a lot of effort goes in both sides to kind of -- to create a swap of when they can be completed, they're very beneficial.

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

We are and -- I mean, we're doing that right now. In fact, that's -- we do have a partner, so we've got some strength even before the Eagle Ford Shale.

Yes. We -- even throughout 2017, yes, we were involved in most of the acreage that did trade-ins. We -- we're at the high bidder, but we were actively -- the parts that we like, we were actively pursuing that under -- and again, we had the luxury of having a USG, who's very interested in the same thing. So it gives us some financial strength. But yes, and I think there's a -- we're excited about the evident -- more focus on that in 2018, especially after we -- if we complete the refinancing because we do think our -- that there are going to be bolt-on opportunities of all different sizes available.

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.

All right. 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've gone through these slides and as I look at the Caddo Parish and the Hunter wells and the well performance. I look at the Bossier area and DeSoto Parish and Sabine and I look at the well activity and the performance there. I look at Harrison County and Panola County. I look at our wells (inaudible) and I look at the offsite operators that are active in that area. I mean, really, how could you not be excited about the future of Comstock? With very little money, I think we've been -- we've produced incredible performance in the Haynesville/Bossier. There's a drilling program and our JV partner, as Roland mentioned earlier and I did, USG, is perfect for us and for them. It is a true win-win. And then the last week and we had met some of you -- but we got to speak at a conference in Shreveport, which is just Haynesville producers, for the most part. There were probably 600 or 700 people in the audience. And then we were in Dallas at a conference, and there were 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 honor our debtholders and create as much wealth as possible on a per-share basis for all equity stakeholders. And we always entertain all opportunities that's out 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 of 2015, 3 years ago, would be able to pull Comstock out of the Deep Valley, the E&P sector, entered into around Thanksgiving of 2014, which -- it was a generational downturn that wiped out trillions of dollars of market cap in reserves to the entire energy sector and caused hundreds of energy sector companies to go away. So over the past 3 years and especially in 2017, if you listened 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 assure 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 could have spent it elsewhere and for your belief in the business plan, those 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.