Comstock Resources Inc (CRK) 2017 Q3 法說會逐字稿

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

Thank you, Gigi. And I know this is a busy hour for earnings. So all of the people that are attending, thank you for listening to us. Welcome to Comstock Resources Third 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 titled Third Quarter 2017 Results.

I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; and Dan Harrison, our Vice President of Operations, who's making his first conference call appearance today. Dan joined Comstock in 2008. He graduated in 1985 from LSU with a Petroleum Engineering degree and has held positions at Sun Exploration, Oryx, Pioneer Natural Resources, Prize Energy, Cimarex Energy in various capacities, including production engineer, drilling engineer and operations engineer. Our entire operations team has delivered stellar performance in our third quarter as Dan will discuss during his reports. So welcome Dan. During this call, we will discuss our third quarter operating and financial results as well as covering our outlook for 2018.

If you will go 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 and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Our 2017 third quarter summary, Slide 3. A summary of our third quarter is outlined on slide 3, where you can see we had a solid quarter driven by our successful Haynesville Shale program. The recent fall in our stock price is not correlated to the company's operating performance and outlook for next year, as we hope to demonstrate in today's call. Our natural gas production has grown by 42% as compared to the third quarter of last year; and is up 51% if you exclude the production from the properties we sold last year. Oil and gas prices were also improved in the third quarter as compared to 2016. Our natural gas price is 14% higher and oil prices were 10% higher than the third quarter of 2016. The higher natural gas production caused our sales to grow by 40% to $70 million and our EBITDAX increased by 69% to $50 million. Cash flow from operations for the quarter was $32 million, a 553% increase over 2016.

Our Haynesville drilling program is driving the production increases and the improved financial results. All of our Haynesville and Bossier wells drilled continue to perform above our type curve. The joint venture we have with USG has allowed us to continue to grow our inventory of Haynesville and Bossier Shale locations which sat at over 800 today.

We're very focused on improving our balance sheet by growing our cash flow and EBITDAX and believe we will be positioned in early 2018 to refinance our expensive debt. We announced today that our Board of Directors has approved the potential sale of our Eagle Ford Shale properties, which could generate proceeds of $200 million to $300 million. We typically don't give a target range, but we knew each one of you would be asking selectively. The important point is that the Eagle Ford Shale asset is a Tier 1 oil asset in a Tier 1 basin that we will aggressively market, and we intend to use the proceeds to refinance our balance sheet. The proceeds from the sale along with our growth and reserves in EBITDAX shall allow us to retire, in part, and refinance our first and second lien bonds. We have total liquidity of $150 million, which is more than adequate for us to carry out our planned 2018 drilling program.

If you go to Slide 4, an important slide for the Haynesville Shale JV. As we announced on October 11th, we have expanded our joint development program with USG, which is outlined on Slide 4. The initial activities of the joint development program have been focused primarily in Caddo Parish, Louisiana, where, to-date, USG has acquired over 7,000 net acres targeting the Haynesville Shale, allowing Comstock and USG to drill 34 extended lateral wells. We have drilled 3 10,000-foot lateral wells so far and are currently drilling a fourth well. Completion operations on these wells will commence later this month. We are participating for a 25% working interest in these wells and may increase our working interest participation by mid-2018 to 40%.

USG is also participating in 4 of our wells being drilled targeting the Bossier formation in Sabine Parish, Louisiana. USG will pay us $1.4 million for the right to participate for 50% of Comstock's working interest in each of the 4 Bossier wells. $400,000 of that amount is only paid if a well meets or exceeds our production target after 6 months. As a result of making a commitment to the mineral owners to drill the 4 Bossier wells, we also earned a lease on an additional 640 acres adjacent to our Toledo Bend field, we're granted a reduction in the royalty on these wells from 25% to 18.75%, and we're assigned an additional 12.5% working interest in the wells by drilling these 4 wells.

USG also agreed to participate in the drilling program on certain of our acreage in Harrison County, Texas that will target the Haynesville Shale. We have approximately 7,000 net acres in Harrison County, Texas, which has 34 Haynesville Shale locations on this acreage. Similar to the Sabine Parish agreement, we will be paid $1.1 million for each location for acreage and infrastructure related to the well location. The participation of USG will allow us to acquire additional acreage in this area, which will add additional drilling locations to our inventory.

For each well drilled in the program, except for the 4 Bossier wells, we're paid $80,000 per well for engineering and geological services.

Now I will turn it over to Roland, who will report on our financial results. Roland?

Thanks, Jay. Slide 5 shows the growth in our natural gas production being generated by our Haynesville Shale drilling program. In the third quarter, our natural gas production averaged 217 million per day, up 51% from the third quarter of 2016 and up 14% from this year's second quarter, if you exclude the production we divested of in December of last year. In October, we averaged around 230 million a day, and we expect to see the fourth quarter average in the neighborhood of 240 million per day. And then with the drilling program in 2018, which is fairly similar to this year in cost, we estimate that our 2018 natural gas production would average between 250 million to 270 million per day. This is a little higher than the press release guidance as those estimates were very conservative.

It's always important to point out that our Haynesville operations are in an area with a substantial regional natural gas price advantage compared to the Northeast markets, and we have not committed to onerous firm transportation and gathering arrangements, like many of the other large Haynesville producers.

As shown on Slide 6, our regional basis differential to Henry Hub is only around $0.12 for the last 12 months and while the transportation to Henry Hub from the Northeast, which is about 1,200 miles away, has averaged $0.94 for the same period. Gulf Coast industrial demand, exports to Mexico and LNG exports continue to grow in the Gulf coast region. Our gathering and treating costs to get our gas to the major markets is around $0.22, giving us high price realizations, which are very important in this current lower gas price environment.

Slide 7 shows our hedge position we put in place to lock in the high returns of the Haynesville Shale drilling program. We had 99 million per day hedged in the third quarter at $3.38 per Mcf. We have a similar amount hedged for the fourth quarter at the same price. And we're currently working on putting in hedges for our 2018 program, and we'll target having 60% of our natural gas production hedged as we get into 2018.

On Slide 8, we summarize our oil production. Our oil production averaged 2,500 barrels per day in the third quarter, showing continuing decline due to lack of any drilling activity since 2014 and the sale of our Burleson County Eagle Ford Shale properties in 2015. Most of our oil production currently is from our Eagle Ford Shale properties in South Texas, which will probably be shown as held-for-sale by the end of the year. We expect our oil production 2018, prior to this sale, will approximate between 2,000 and 2,200 barrels per day.

Slide 9 shows how much production we had shut-in, in the first 3 quarters of this year. Shut-in natural gas production averaged 2 million per day in the first quarter, which was related to wells shut-in for offset frac activity. In the second quarter, the shut-in production averaged 8.2 million per day, much of which was related to severe storms and tornadoes in our Haynesville operating area in May of 2017, which caused electrical power outages in the region. In the third quarter, our shut-in production averaged 8.9 million per day. This is mostly shut-ins due to the necessary -- that were necessary due to offset frac activity for either our operations or for activity by offset operators. Our oil production has been shut-in due to offset frac activity from nearby operators in the Eagle Ford area. In the first quarter, we had about 105 million barrels per day shut-in, 59 barrels per day in the second quarter and 56 barrels per day in the third quarter.

On Slide 10, we show how our producing costs continue to improve as we shifted toward drilling our lower-cost Haynesville Shale properties versus the higher-cost oil projects. Operating costs improved to $0.73 per Mcfe this quarter as compared to $1.48 in 2014 and $1.10 in 2016. With much of our production coming from new wells in the Haynesville Shale, which are exempt from production taxes in their first couple of years, our production taxes averaged $0.07 in this quarter as compared to $0.36 back in 2014 and $0.08 in 2016.

The field level producing costs were also down to $0.44 in the third quarter as compared to $0.97 in 2015 and $0.76 in 2016. Our depreciation, depletion and amortization per Mcfe produced has also come down dramatically and was $1.52 per Mcfe this quarter as compared to $5.74 in 2014 and $2.26 in 2016. The improvement is due to the low finding cost of our Haynesville Shale wells. If you exclude the Eagle Ford operations, our total operating cost per Mcfe would've been $0.57 this quarter, which includes gathering and production taxes and lifting, and our DD&A per Mcfe would've been $1.27. So on a pro forma basis, for the divestiture that we hope to complete next year and post the refinancing of our debt, our cost structure will be one of the best in the industry.

On Slide 11, we summarize the third quarter financial results. The growth in gas production, improved prices and lower operating costs continue to drive an improvement to our sales and cash flow. Our natural gas production increased 42% and natural gas prices increased about 14%. As a result, our oil and gas sales this quarter were up 40% to $70 million as compared to the third quarter of 2016. Our EBITDAX was up 69% to $50 million, and our operating cash flow of $32 million was substantially improved from the cash flow of only $5 million that we had in the third quarter of 2016.

As I pointed out earlier, our producing costs have also come down substantially. Lifting costs in the quarter were down 12%, and our DD&A was down 13% due to the improvement in the DD&A rate. This is all despite the 34% increase we had in overall production. Our G&A costs were up in the quarter by $2 million, reflecting the increase in our activity level as compared to last year.

For the quarter, we reported a loss of $24.7 million or $1.67 per share. This loss includes several unusual items, including an unrealized mark-to-market loss on the hedge contracts of $2 million, noncash amortization of the discount recognized on the bond exchange we completed last September of $9.9 million, which just simply offsets the $100 million gain that we recorded last year; and a loss on the small property sale we completed this quarter of $1 million. If you exclude these items, the net loss in the quarter would've been $0.80 per share.

On Slide 12, we recap the financial results for the first 9 months of this year. Natural gas production grew about 24%, and gas prices increased about 37%. Also, we had an improvement in oil prices of 30%. So the result was our oil and gas sales for the first 9 months of 2017 were up by 45% to $187 million as compared to the same period in 2016. Our EBITDAX was up over 100% to $128 million, and operating cash flow of $74 million was substantially improved from the cash flow deficit of $17 million that we had in the same period in 2016. The improvement in producing costs were also contributing to the improved financial results, along with the higher gas production and the improved oil and gas prices. Again, our lifting costs were down 18% in the first 9 months of this year. Our DD&A is down 17% due to the lower rate. Then our -- overall, our G&A costs were up by 24%. And for the 9-month period, we reported a loss of $69 million or $4.74 per share. This number also includes the same unusual items that if you exclude those items, we would have had about a $3.60 loss per share.

On Slide 13, we covered the balance sheet at the end of the third quarter. We ended the quarter with $25 million of cash on hand and $1,175,000,000 of total debt outstanding based on the principal amount. If you include the undrawn credit facility and the available pay-in-kind interest of our first lien bonds that we are continuing to pay in cash, our total liquidity is relatively the same as it was throughout most of this year at $150 million. The potential sale of the Eagle Ford Shale properties should allow us to retire in part, and refinance in part, our first and second lien notes. The sales proceeds, combined with the new secured bank credit facility and unsecured bonds, should give us the necessary tools to reset the balance sheet and substantially lower our interest cost. We're targeting March of next year to kind of get all this accomplished.

Slide 14 recaps our capital spending for the first 9 months of this year. We spent $126.7 million in this period, and we drilled 17 new Haynesville extended lateral wells, which will add 13 net to our interests. We expect to spend about another $38 million in the fourth quarter to finish up our drilling program this year.

On Slide 15, we lay out a preliminary drilling program using the 3 operated rigs that we currently have running. We'll continue to refine and change this program as we get closer to the end of the year. This is earlier than we usually put this out, but we wanted to kind of show that we are dedicated to running a program that's going to be funded exclusively with operating cash flow, and this is a conservative program that we think will meet our needs. So we expect to have 2 of the rigs that we have operating, drilling wells under the joint development program with USG, and then we expect to have one drilling our legacy acreage in the Haynesville Shale. So under this plan, we will have drilled 26 wells or 13.8 net wells, all Haynesville wells in 2018, and this would cost approximately $145 million. We also expect to spend another $14.8 million to complete wells that were drilled in 2017 that will carry over into 2018 for completion. And then we have 2 refracs -- in-liner refracs budgeted in this budget for $6.7 million. Then we have a -- budgeted an additional $3.4 million just for other miscellaneous activity.

So depending on the industry conditions that we experience in 2018, we can increase or decrease this budget as circumstances warrant. One of the potential increases is we may add a Bossier Shale program, following up on the 4 wells that we're drilling here at the end of this year.

Dan will now take over and bring you up-to-date on our Haynesville drilling program.

Thanks, Roland. I'm excited to take over from Mack and update you on what's going on with our Haynesville Shale operations.

You can see on Slide 16 is a good overview of the Haynesville Shale and Mid-Bossier Shale play in North Louisiana and East Texas. All 69,000 of our net acres in the Haynesville play are reflected in blue on this map. We operate the majority of our net acreage position and have an average working interest of 78.7% over the 88,000 gross acres we have an interest in. The average net revenue interest in our acreage is 80.5%. We're drilling 25 wells on our acreage this year and tentatively plan to drill a similar number next year.

As most of you know, the Haynesville Shale is undergoing a resurgence in recent years as longer laterals and larger stimulation treatments have led to much higher production rates and EURs. As a result, which I'll show later, the Haynesville Shale wells have strong returns at today's $3 natural gas price.

The location of the Haynesville near the Henry Hub, combined with our competitive gathering and treating contracts, gives us a premium natural gas market for our Haynesville production.

We recently finished remapping our acreage after the completion of acreage swaps of 2 offset operators as well as adding new acreage. We've been able to greatly increase our inventory of 10,000-foot laterals or 2 section laterals, as we call them, which now stands at 163 in the Haynesville and 183

in the Bossier. Our bread and butter laterals of 7,500 feet or 1.5 section laterals stand at 97 in the Haynesville and 88 in the Bossier. And our single section inventory stands at 200 in the Haynesville and 118 in the Bossier. So this gives us a total of 849 locations in the Haynesville and Bossier Shale, and 82% of these are operated by us.

In addition to the Haynesville and Bossier opportunities, we also have 285 horizontal Cotton Valley locations to drill. We also have a very good inventory of refrac opportunities across our 115 older vintage Haynesville producers, based on the strong results that have been recently posted by some other operators in the play.

Flipping over to Slide 18. Slide 18 shows a comparison of our Gen I and Gen II completion IPs. The results averaged over 1,000 feet of completed lateral length. Just as a reminder, Gen I design uses 2,800 pounds per foot of sand, loading applied over a 250-foot stage length, utilizing 5 per clusters at 50-foot spacing. Our Gen II design uses 3,800 pounds per foot of sand, applied over a 150-foot stage length, also utilizing 5 clusters but at 30-foot spacing. Our 13 Gen I wells give us 3.3 million cubic feet a day per thousand feet of lateral while our 15 Gen II wells have given us 4.3 million a day per 1,000-foot lateral. So Gen II completions have given us a 32% improvement in our IP ratio over Gen I.

As you can see on both Slides 19 and 20, it shows you all 27 Haynesville wells, plus the one Bossier well that we have put to sale since the beginning of our program in 2015. The wells with the red callouts are the 13 Gen 1 wells drilled in 2015 and in the first 3 quarters of 2016. The gold callouts are all the Gen 2 wells we have drilled since late 2016 up through the current date.

Since our last conference call, we have completed 3 additional Haynesville Shale wells. The average initial production rate of these wells was 29 million cubic feet per day. Our Headrick 14-11 #1 well was drilled to a total vertical depth of 11,618 feet with a 7,168-foot completed lateral. The well's IP was at 33 million per day. The Headrick 14-23 #2 well was drilled to a similar vertical depth of 11,496 feet and had a 7,429-foot completed lateral. It's initial production rate was at 35 million per day. The Grantham 30-31 #1 well was drilled to a total vertical depth of 11,198 feet with an 8,456-foot completed lateral and was tested with an initial production rate of 20 million cubic feet per day. [Audio gap] Operational constraints limited the initial rate on the Grantham regarding the higher water production with limited disposal capacity.

We have recently completed frac in the Derrick 21 #2 and the Derrick 21 #3 wells, both with 4,550-foot laterals. And we're -- and just about to turn both of those wells to sales today, and we're completing the BSMC 18-7 #1 Bossier Shale well that has a 7,489-foot lateral. And as of today, we have 7 Haynesville Shale horizontal wells waiting on completion.

You can just see on Slide 20, again, this is the same data presented on the previous slide, we show the wells' initial production rates per thousand feet of completed lateral. This normalizes the results between the wells and better depicts the improved results on the Gen 2 wells versus the Gen 1 wells.

On Slide 21, we display our Haynesville and Bossier wells sufficient -- that have sufficient production history are performing against our 7,500-foot type curve. The red curve represents the average of our 12 Gen 1 wells, which we started drilling in early 2015. These wells now have several years under their belt and continue to perform above our type curve. The purple curve represents the average of our 8 longer lateral Gen II wells, which are outperforming the Gen I wells so far. The light blue curve, which is the average of our 6 shorter lateral wells, which were also completed with the Gen II design. As you can see, they are performing close to the 7,500-foot type curve even with 2,000 foot less lateral length. And finally, you can see the green curve that represents our one Bossier well, which has now produced for well over 600 days and is outperforming the Gen I Haynesville wells.

On Slide 22, we have normalized the data presented on the previous slide to reflect the production per 1,000 foot of completed lateral. The Gen I curve is the average of our 12 wells drilled in 2015 and 2016 and is shown in red. The average lateral length for these wells was 7,194 feet. The green curve is the Bossier well drilled in 2015. The dark blue curve is the average of all of our 14 Gen II wells, which had an average lateral length of 6,454 feet. You can see the Gen II wells are outperforming the Gen I wells on this basis also.

On the next slide, Slide 23, this shows our rate of return forecast cases and the underlying assumptions for our Gen II wells that are [right] at NYMEX, natural gas prices of $2 up to $3.50 applied to the production we expect from each of these different Haynesville wells we drill. We have updated the costs to reflect what we're expecting to spend in 2018. Even with the higher service costs, we still have strong returns for these wells. As you can see at a $2.50 flagged gas price, our rate of returns range from 34% for our short laterals and around 41% for the horizontal wells drilled to 7,500 feet and beyond. At a $3 gas price, the rate of return increases to 60% for the shorter laterals and up to 70% for the longer laterals.

And with that, let's wrap it up, and I'll turn things back over to Roland.

All right. I'll take it from here. Thank you, Dan.

If you go to the outlook, which is Slide 24, let me refer you Slide 24 where I'll cover the outlook for the remainder of 2017 to 2018. Our high-return Haynesville Shale assets are driving our strong growth this year as Roland as has demonstrated and Dan has demonstrated. And our enhanced completion design 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. We're expecting our natural gas production to grow by more than 40%, driven by a 26-well drilling program. A similar 26-well drilling program in 2018 will allow us to grow natural gas production by at least 30%.

The production increase will cause our EBITDAX and cash flow to continue to grow. And it's important to note that we've already grown our cash flow to fully fund the drilling program. Our already low-cost structure has continued to improve with new low-cost Haynesville Shale production. In the third quarter that we reported on today, our lifting costs per Mcfe have decreased by 34% and our DD&A per Mcfe has improved by 35% as compared to 2016. Balance sheet and liquidity continue to improve as we grow our cash flow and EBITDAX. The potential sale of our Eagle Ford Shale asset, combined with growth in EBITDAX, should allow refinancing of our secured debt in early 2018, as Roland has mentioned.

For the rest of the call, we'll take questions from the analysts who follow the company. So Gigi, I'll turn it back to you.

(Operator Instructions) Our first question is from Mike Kelly from Seaport Global.

Jay, Roland, I'm just a stupid equity guy here, so you're going to have to maybe lay out the playbook of how you proceed with this asset sale and debt refi. I guess I'm curious is really kind of what you think the company will look like post execution. What, in your mind, is the critical steps to actually make this happen? And then what concessions, if any, do you think you have to give to bondholders to make this happen as well?

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

Yes. And Mike, I want to comment on that. I'd say if you look at the recap the company had in November of '16, I mean, the second lien note holders made a concession to be converted into equities. And if the stock hits $12.32, then that'll happen. If it doesn't -- which I think that's been the recent pullback in the stock because of this uncertainty, what if it doesn't, what will happen? So what we've tried to do today, and today is the first time we've been able to do this publicly, is to say we've added more Haynesville acreage with our partner USG. We have increased our EBITDAX materially. We funded a program we think will grow production 30% to 40% next year for 2018. We've funded it already in what we think will be our EBITDAX number and -- we should add some material reserves. So if you take that and then you look at a $52, $53 oil price, whatever it is today, and you look at a Tier 1 oil asset, which is our South Texas Eagle Ford -- because we took that 18,000, 19,000 acres, which is held by production, we grew it from 0 oil to almost 13,000 barrels a day. We haven't spent any money on it, really, since '14, so it's 2,200, 2,300 a day. But we set the infrastructure in to drill the remaining 300 locations. So I think our timing will be good to monetize that. I think that'll give us that extra chip that we need as our borrowing base is growing, because it's growing materially. And our goal is to go back to a much less expensive money and a balance sheet that's in the middle of the fairway and for everybody to be rewarded for what all they've done. Whether you're a first lien note holder or second lien or an equity holder, I think we truly have protected everybody. And if there's something that can happen to cause us not to issue quite as many shares or any shares, and we tender or buyout the second lien position, then that'd be even better for the equity owner. That just tells you we're that much stronger as a company. So that's why we even gave a range of what we thought the Eagle Ford might sell for. We don't really know. That's a target range. That's an indication range. So the goal is that we'll use that to refinance our balance sheet. And I think things look wonderful. So -- and Dan's done a really, really good job taking the baton from Mack and so has the whole team. So hope that helps.

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

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

And Mike, our goal is not to kind of put a bandaid on our balance sheet either. I mean, our goal really is to fix it, and it's the interest expense that's killing us. It's not our liquidity. We have liquidity. It's not our inventory of locations. We've increased our inventory. It's not the quality of our assets. It's not the profit margins we have. It's just the sheer amount of expensive debt we had to put on to dance our way through the worst cycle we've had in a generation. So -- and I think we'll continue to do that. And like Roland said, if we get our leverage below 3x, I mean, I think from an equity side, which you're talking about, I mean, I think the stock price will explode in value, and that's our goal because we own a lot of it.

Good stuff. That's great color, and I'd concur with everything you just said. Just maybe one operational one for me. As I look at the number of wells that you put out for next year, the 26 gross, if I just divide that by 3 rigs, it's -- each rig line average an 8.6 wells annually, not sure if that's the right way to look at it, if there's a third rig that's being phased in later. How should we think about each rig line's capabilities now and the potential for that number to have some sort of fluctuation on the gross well front?

Yes. I'll answer this quickly before Dan adds something to it. But yes, basically, I think that -- the base budget there doesn't -- assumes that one of those rigs gets released before the -- probably late third quarter of next year. So yes -- but generally, a lot of the wells are 10,000-foot laterals, so they definitely take longer. So I mean -- so it's a -- they're going to take longer to drill. So I'll let Dan kind of comment and kind of frame for those.

Yes. So really the majority of the locations we're going to be drilling next year are 2 well pads. We've got a lot more of the 10k laterals we're drilling next year that do take longer. You can't get quite as many wells per year. We do have -- just one of the rigs is going to be running in our legacy area. We're going to have 2 of the 3 rigs will be running on our JV acreage where we'll be participating in a lot lower working interest. That's going to keep our capital requirements much lower. But as Roland said, we've got -- with the plan now to maybe roll off one of the rigs towards the end of next year.

One other thing, Mike, you asked, and I think it's a key question, what is your playbook? Even though we can't tell you what it is totally, I think today, the market can see we have one. We might tell you that we're going to attempt to sell Eagle Ford, but until we put it in writing and hire somebody to do it, maybe we don't. But today, we're going to do that. Our goal was to have EBITDAX of $50 million. Well, you didn't know that till this morning at 5:45 am Central Time. So our goal is to grow our JV acreage. You didn't know we had really grown it to 7,000 acreage till this morning. Our goal was to add some value in Texas, in the Waskom area and Harrison County. And guess what? We brought in USG, which has great muscle as a financial partner and we'll drill Haynesville wells there. We want to drill more Bossier wells. So we go to the mineral owner who we've known since 1995 and they've got a section, or 2 or 3 and we work a deal, so we drill Bossier wells. Who? With a partner. We promote the partner. So all these things are part of the playbook that are accretive. And I think as it plays out month to month to month, I think we'll get stronger and stronger and stronger. I do believe our worst days are in our rearview mirror. So we'll see what happens to commodity prices. But from the operations and financial side, it couldn't be better.

And our next question is from Ron Mills from Johnson Rice.

Question now -- I don't know maybe for Dan. But when I look at your Haynesville position, it's gone up about a 1,000 acres. I'm assuming that may be related to the JV acreage increasing, yet you're -- the number of total Haynesville and Bossier locations went up by, plus or minus, 20%. What's driving the increase in the number of locations, given a fairly similar amount of acreage? And then also there's a big shift in terms of 56% of the Haynesville locations are now 7,500 foot to 10,000 versus 40%. So it's a combination of what's driving the absolute level of inventory increase, and then also the -- is it acreage drops that's driving the higher percentage of longer laterals?

Yes, yes. And we haven't really, Ron, refreshed that number since last year. So there's a lot of things have happened, and we just finished the remapping. But we did some pretty -- very productive trades with 2 operators in the Haynesville, so in our -- and that added new locations that before we didn't have enough acreage to have a location, but it also definitely helped on the more longer laterals, especially in the 10,000-foot area. The JV operations, which doesn't show up a lot in the net acres, has added a lot of locations. They really weren't -- the number before really didn't include the JV. So I think it's -- and then I think a lot of work in Harrison County. We've done a ton of work. Locations are there expects -- before, we didn't have any extended laterals in Harrison County. So I think it's just the -- it's really a -- one, that number was very stale, that has been out there for since last -- probably almost a couple of years old number. And so it just reflects all the work that we've been doing to enhance the inventory across-the-board. So it's a very good snapshot today, but obviously, it didn't happen just in the last month. It's the culmination of everything, including the new relationship with USG, that has built up the inventory.

Well -- and I think it's driven by the importance of locations. When we spudded the first Haynesville well in February of '15, it didn't really matter how many locations we really had because we didn't have one extended lateral enhanced completed well. By the end of '15, you've got 10 of them, including a Bossier. By '16, you still don't have much money. You drill 3 wells and you backwardate and drill some more. And then you get serious because you've got a partner. And any contiguous acreage that you can add, you try to add it. And then you add, like Roland said, the Waskom area in Texas. So you end up with what we have now. A lot of the trades happened last year. We saw Chesapeake's and others sell out some of their acreage. So the new acquiring operators were able to trade some acreage that they want, we want and we have more locations as a result.

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

And you've highlighted these issues a couple of times. I know there have been some recent A&D transactions over there, where Rockcliff have -- has bought a couple of assets. Can you talk about any recent activities? Have people drilled extended laterals wells with the newer completion techniques yet? Or what's driving the confidence to start including those locations?

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

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

What's interesting, Ron, you go back with us to probably '08 when we drilled the first Haynesville well. Now the first 4 wells we ever drilled back in '08, '09, let's say, one of them was a Bossier, kind of where we're drilling the Bossier today. Second one was in the Waskom, Harrison County. Third was in Caddo and then we ended up in DeSoto Parish. So kind of those 4. It may not be in that exact order. But that's where we targeted growth back in '08, '09. So that goes back -- and Dan joined us in '08. So that goes back to the history we have, and I think that's one of the reasons we have USG as a partner, because they said you've got such a depth of history, we need that. We said, "Well, that's a good thing because it's a win-win for everybody."

Great. And then on the updated well costs, they've increased more to inline with what other guys have been talking about for 7,500 and 85 -- or in 10,000-foot laterals. Is that inclusive of savings that would come from 2-well pads, or in terms of the economics that you now provide, are those still for single-well pads?

So that -- Ron, that's a good average of kind of single wells and 2-well pads. We really haven't done too many 2-well pads to-date to really have a good historical trend. But most everything we're to be doing going forward is going to be on 2-well pads. So I think we've actually got the potential in there to probably shave a few extra dollars off of what we've presented here.

And our next question comes from David Epstein from Cowen.

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

Yes, that's correct. Obviously, we -- the bonds are what they are and the authorizations are what they are. So the plan is, I think, with the sale proceeds to look at all the tools we have in hand. And we think most likely that unless the stock really causes conversion, those bonds probably will be called and not converted. That's just -- that's a good possibility.

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

Yes. So this is Dan. I think time will tell. We still won't have that well in production for probably a couple of months now and 2 and a half months. And typically, the wells -- all of these wells with the newer, larger frac jobs we do flow back a lot of water, obviously, in the early time frame. And so when we go to these longer laterals, we've had to flow them a little bit longer just even -- basically, every well, we flow them longer to achieve an IP. This well's in an area where we didn't have just a little bit higher average water production. And with the larger frac job that we put on it, we got a lot larger water rate on it initially and it just restricted being able to get an IP in that early time frame. And of course, as you keep flowing the well, you lose a little bit of flowing pressure. It kind of diminishes being able to get the normal IP that you normally would. We were definitely limited with being able to get rid of the water off the location, that was also a factor. We just couldn't find enough trucks to basically -- to dispose of it. So we had to cut the rate back a little bit.

(Operator Instructions) And our next question comes from Joshua Gale from Nomura Securities.

I appreciate all that color on the location count. It's immensely helpful. Just had a question about the wells. If I take the net well count and the CapEx budget for 2018, it's applying about -- implying about $10.5 million on average but I know that 2/3 of the rig activity is going to be focused in areas where there's a lot of 10,000-foot laterals. So the well cost on Slide 23, is that maybe a conservative estimate and by drilling 2 and -- 2-well pads and completing in batches of 2 or 4, there's potentially some savings baked into that operating plan for 2018?

This is Dan. So there's -- the prices that we have here for the costs are really kind of an average of really some single-well pads and 2-well pads. They're -- with exclusive -- basically, for the remainder of this year and into next year with most everything being on 2-well pads, there is some potential there to probably shave off a little bit of cost from what the numbers are here. But I'll also caution that we -- it also depends on what -- where service costs are going to be next year. We think we've kind of gotten past most of the really rapid increase in costs we've had this year. And hopefully, this year and into next year, we're looking at something a little bit kind of level from here going forward. Just talking to our service providers, we're expecting costs to kind of level out where we're at.

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

Yes. That's a status quo type of assumption. They were not assuming a different capital structure for this basic drilling program that we're putting in. I think post refinance, we're -- if we have a lot lower interest costs, we could -- we probably would have a larger capital program to drive more growth. But that's a status quo assumption, that the capital structure stays the same. And we always budget to pay the first lien interest in cash, so that's also -- it comes out of the cash flow also, so.

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

That is pretty fair, yes.

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

All right, Gigi. Going back to Mike Kelly who is from Houston, which is the home of the Astros, and his word playbook, I would tell you that the Astros won the World Series in baseball last night. When they did that, they gave us their playbook. So let's just hope we can implement the playbook we have that they've given us as well as they did. If we do, then we'll do what they did, which is be really successful.

That's it. Thank you, Gigi.

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