Comstock Resources Inc (CRK) 2019 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Q4 2019 Comstock Resources Earnings Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the call over to Jay Allison, Chairman and CEO. Please go ahead.

Michelle, thank you, and -- when we announced the Covey Park consolidation with Comstock on June 10, 2019, I'll tell you, we were anxious for today, a day where we could show you what the consolidation of the 2 asset bases looks like and really what the craftsmanship and the management of this group of 207 collective employees at Comstock, from top to bottom, plus the Comstock Board, can create in this extremely soft energy market. Our results that we'll show you today are really strong. We are profitable. We have free cash flow. I think we have the lowest G&A in this sector. We also have industry-leading margins and industry-leading low costs that created the strong results that we'll review today with you. Plus, we have a very deep inventory of drilling locations around 2,000 [wells] (added by company after the call) that is probably 94% HBP'd for future growth.

I want to say thank you for listening to our story. I know there's a lot of distraction out there today. I want to thank you for listening. I want to thank Jerry Jones and his family for believing in the business plan, along with Denham Capital and Covey Park for believing, too. I also want to thank our bondholders and our banks that support us and, of course, the almost 10,000 equity owners who own the stock. And I'll tell you, that includes our new shareholders in Shreveport who contributed their oil and gas assets to Comstock for stock in November of 2019.

Our goal to you is to act right. Whatever market we're in, we're going to act right. And we're not in a good market. We will not panic. We will manage with a steady hand. This group of management and our Board created our strong results in tough times. Nothing has changed. We'll continue to use our collective skills to capitalize on this market, always focused on creating a stronger balance sheet.

So again, welcome to Comstock Resources fourth quarter 2019 financial and operating results conference call. Today, I'll review our fourth quarter 2019 earnings and drilling results. You can review the slide presentation during or after this call by going to our website at www.comstockresources.com and downloading our quarterly result presentation. There, you'll find a presentation entitled, "Fourth Quarter 2019 Results."

I am Jay Allison, the Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; and Dan Harrison, our Chief Operating Officer. They'll both give you reports today that I hope you'll like.

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.

On Slide 3, we highlight our major 2019 accomplishments. On July 16, we completed the acquisition of Covey Park Energy, which added significant size and scale to the company. We acquired 250,000 net acres in the Haynesville shale with approximately 1,200 net drilling locations. We added over 700 million cubic feet a day of production and 2.9 trillion cubic feet equivalent proved SEC reserves.

We successfully integrated the Covey Park operations in less than 6 months, including consolidating the 2 corporate offices into our Frisco office with a 41% reduction in headcount. We did achieve our combined targeted P&A of $30 million as we advertised.

After the Covey Park acquisition, we now have industry-leading low-cost operations, and we have high margins. In 2019, our drilling program was very, very successful. We drilled 64 gross or 46.5 net wells and completed 61 gross or 45.5 net wells, with an average IP rate of 25 million cubic feet equivalent per day. The drilling program drove a 37% increase in production on our pro forma production basis.

We also completed, as I mentioned earlier, a bolt-on acquisition, by issuing 4.5 million shares of common stock, which added 3,155 net acres, 12.7 net drilling locations and 76 Bcfe of proved reserves.

Overall, we grew our SEC proved reserves by 125% to 5.4 trillion cubic feet equivalent at an all-in finding cost of $0.72 per Mcfe, while our SEC PV-10 value grew by 85% to $3.3 billion.

On Slide 4, we cover some of the highlights of the fourth quarter. The fourth quarter results represent the first full quarter impact to the operations of Covey Park, and the numbers proved up the strategic, operational and financial benefits of the merger that we advertised.

Our Haynesville/Bossier shale drilling program continues to deliver strong results. Comstock and Covey Park have drilled and completed a combined 217 operated wells since 2015, which had an average IP rate of 23 million cubic feet per day. That is more than any other operator in the play during this time period.

Our drilling activity drove the 37% year-over-year growth from the fourth quarter of last year on a pro forma basis. We've also been driving down our well cost in the Haynesville. Dan Harrison and his team have done a great job at that. Our latest well cost per lateral foot are 20% lower than what we averaged in the fourth quarter of 2018. The strong natural gas production growth was offset by weaker natural gas prices in the fourth quarter.

For the quarter, we reported oil and gas sales of $309 million, adjusted EBITDAX of $235 million, operating cash flow of $188 million, or $0.66 per share, and adjusted net income of $49 million, or $0.22 per share.

Now I have Roland Burns to cover our financial results in more detail. Roland?

All right. Thanks, Jay. On Slide 5, we cover our proved reserve base at the end of 2019. We grew our proved reserves from 2.4 Tcfe to 5.4 Tcfe in 2019 primarily from the 3 Tcfe we acquired in last year, including the Covey Park acquisition.

Our drilling activity added 317 Bcfe to proved reserves, and we had 267 Bcfe of positive performance-related revisions. The reserve additions were partially offset by divestitures of 50 Bcfe and negative price-related revisions of 232 Bcfe. Our all-in finding cost for 2019 came in at an attractive $0.77 per Mcfe, or $0.72 if you exclude the price-related revisions.

Our reserves are 98% natural gas, and 36% of our reserves were developed based on volumes. On a value basis, 65% of the reserves were developed. The PV-10 value of our proved reserves was $3.3 billion. 93% of the proved reserves are in the Haynesville or Bossier shale, 3% are in the Bakken Shale and 4% are in our other regions.

In addition to the 5.4 Tcfe of SEC proved reserves, we have an additional 2.9 Bcfe of proved undeveloped reserves, which were not included because they're not expected to be drilled within the 5-year window required by SEC rules. We also have another 4 Tcfe of 2P or probable reserves and 5.5 Tcfe of 3P or possible reserves, for a total reserves of 17.8 Tcfe on a P3 basis.

Slide 6 combines Comstock and Covey Park's production from the Haynesville/Bossier shale since 2016. In the fourth quarter of last year, production from our Haynesville/Bossier wells is up 37% to almost 1.3 billion cubic feet per day as compared to the 915 million cubic feet per day that we had in the fourth quarter of 2018.

Production grew almost 14% sequentially from the third quarter due to the completion of 23.1 net wells during the fourth quarter, which represents the highest number of wells ever completed during a single quarter on a combined basis.

In the first quarter of 2020, we see our Haynesville/Bossier production staying relatively flat to this level, with only 9 net wells expected to come on production during that quarter.

Slide 7 recaps the production we had shut in during the quarter, and this was mostly shut in for offset frac activity. We were pleased to see that our fourth quarter shut-in volumes decreased to only 2% of our total production as compared to 3% in the third quarter.

On Slide 8, we summarize the financial results for the fourth quarter of last year. Our production for the fourth quarter totaled 125 Bcfe, including 577,000 barrels of oil. This is 247% higher than our production in the fourth quarter of 2018.

Our oil and gas sales, including realized hedging gains, were $309 million, 109% higher than the fourth quarter of 2018. Oil prices averaged $50.36 per barrel, and our realized natural gas price averaged $2.30, including hedging.

Our adjusted EBITDAX came in at $235 million, 109% higher than 2018. Operating cash flow was $188 million, which was 97% higher than 2018. And we reported net income of $40.8 million in the fourth quarter or $0.19 per fully diluted share. Adjusted net income, [excluding] (corrected by company after the call) unusual or nonrecurring items, was $49.1 million or $0.22 per diluted share.

On Slide 9, we summarize our financial results for all of 2019. Production for the year was 309 Bcfe, including 2.7 million barrels of oil represented an increase of 180% from the prior year.

Oil and gas sales, including realized hedge gains, were $821 million, 112% higher than 2018. Oil prices in 2019 averaged $49.64 per barrel, and our realized gas price averaged $2.35 per barrel, including any hedge gains that we recognized. Overall, our natural gas price realization was down 18% from the prior year.

Our adjusted EBITDAX was $614 million, 114% higher than 2018. Operating cash flow was $468 million, up 124% from 2018. And we reported net income for 2019 of $74.5 million or $0.52 per diluted share, but adjusted to exclude unusual items, including the merger cost of the Covey Park acquisition, our net income was $122.3 million or $0.77 per diluted share.

On Slide 10, we present our operating results pro forma for the Covey Park acquisition for all of 2019 since the acquisition was brought into our numbers in the middle of July. The fourth quarter was the first full quarter that included Covey Park's operations, so pro forma production for all of 2019 on a pro forma basis was a total of 450.7 Bcfe, with oil and gas sales of $1.2 billion. The pro forma natural gas price for all of 2019 would have been $2.48 per Mcf.

On Slide 11, we summarize the hedge positions that we have in place for our oil and gas production. For 2020, we have around 600 million a day of our natural gas production hedged and about 3,450 barrels of our oil production hedged. Since our last reported earnings, we've added 112 million cubic feet per day of gas swaps in 2020. The weighted average strike price of our 2020 gas hedges is $2.66 per Mcf, and our plan is to continue to target hedging 50% to 60% of our production on a rolling 12-month basis.

On Slide 12, we detail our operating cost per Mcfe. Our operating cost fell to $0.55 in the fourth quarter as compared to the third quarter rate of $0.59. Our gathering costs were $0.24, production tax averaged $0.08 and our overall field level lifting costs were $0.23.

On Slide 13, we detail our corporate overhead cost per Mcfe. Our cash G&A cost per Mcfe fell to only $0.04 in the fourth quarter as compared to the third quarter at $0.07. As we said before, one of the most significant benefits of the Covey Park merger is the improvement in this metric due to the reduction in personnel from the two different organizations. With this low overhead, we now have the lowest cost structure in the industry.

On Slide 14, we detail the depreciation, depletion and amortization per Mcfe for the quarter and for prior quarters. So in the fourth quarter, our DD&A averaged $0.89 as compared to $0.79 in the third quarter.

On Slide 15, we recap our 2019 spending on drilling and development activity and then what we expect to spend this year. Last year, we spent $511 million of development activities, of which $486 million was related to the Haynesville shale operation. We drilled 64 or 46.5 net operated horizontal Haynesville shale wells in 2019. We also completed 15 or 11.6 net wells that we drilled in 2018.

We spent almost $20 million drilling for, or 2.2 net, Eagle Ford oil wells and about $5.5 million on our Bakken properties. In the fourth quarter, we had $155 million in capital expenditures, and we completed a $42 million acquisition funded entirely by issuing common stock. In that quarter, we also generated operating cash flow of $188 million, resulted in free cash flow of $23 million in the quarter after we also paid the $9.7 million dividend on the preferred shares.

We were running a combined 9 operated rigs in the Haynesville when the Covey Park merger closed. In November, we announced our plan to reduce our rig count to 6 in 2020 in response to the lower gas prices at that time. Given the further deterioration in natural gas prices, we're now planning to have a 5-rig program in 2020. Using 5 operated rigs, our budget will be approximately $421 million, and we expect to reach total depth on 46 wells or 34.3 net operated Haynesville wells. In addition, we'll be in various stages of drilling on 8 or 7.4 net wells at the very end of 2020. At the lower rig count and with the current gas prices, we still expect to generate significant free cash flow of approximately $150 million to $200 million in 2020, despite the impact of this current lower natural gas prices.

On Slide 16, we show our balance sheet at the end of 2019. We currently have $1.250 billion drawn on our revolving credit facility, which has an elected commitment of $1.5 billion and $1.575 billion borrowing base.

We had a year-end cash position of $19 million, so our current liquidity position is at $269 million. We also have $1.475 billion of senior notes outstanding comprised of $625 million of 7.5% senior notes due in 2025 and $850 million of 9.75% senior notes due in 2026.

With no debt maturities until 2024, and our current leverage ratio comfortably below our required leverage ratio covenant of 4x, we're well positioned to weather the current low gas price environment.

Now I'll turn it over to Dan to cover the fourth quarter drilling results in more detail.

Okay. Thanks, Roland.

Flip over to the next slide and you'll see the latest outline of our current 309,000 net acre position. We currently have 1,983 net locations identified on our acreage, which we will cover in a little more detail on the next slide.

95% of the acreage is currently held by production, which translates into few drilling commitments and allows us ample flexibility with our rigs and our drilling schedule for the changing market conditions. We also control the majority of the acreage with a 91% operated position, and an average 76% working interest.

Our current well count increased to 217 wells turned to sales since re-entering the play in 2015, with the new wells having an average IP of 23 million cubic feet per day. Of note is that 79 of these 217 new wells were completed in 2019 alone, with an average lateral length of [8,008] (corrected by company after the call) feet.

On Slide 18, this is a detailed summary of our latest Haynesville/Bossier drilling inventory as of year-end 2019. Our total gross operated inventory now stands at 2,395 locations. Our average net interest is 76%. This equates to 1,809 net operated locations. We also have 1,451 gross non-operated locations with an average net interest of 12%, which represents another 175 net non-operated locations.

Within our gross-operated inventory, we currently have 585 short laterals, 936 medium length laterals and 874 long laterals. 60% of our gross operated locations are located in the Haynesville, and the remaining 40% are in the Bossier. This inventory provides the company with approximately 50 years of future drilling locations based on our forecasted 2020 activity levels.

Overall, Slide 19, you can see a summary of the 20 new wells we have completed and turned to sales since our last call and also an outline of where these latest wells are located across our acreage. As you can see on the map, this new activity has been spread out fairly evenly across our acreage position from East to West.

The initial production rates range from 15 million to 45 million cubic feet per day with an average IP of 24 million cubic feet per day. The wells were drilled with varying lateral lengths and included a large number of short laterals than the last update. The completed lengths range from 4,337 feet up to 10,191 feet, with the average length at 6,926 feet.

All the wells were completed with sand loadings ranging from 3,000 pounds to 3,800 pounds per foot, with the average at 3,550 pounds per foot. At this time, we also have 15 additional wells that we are currently completing.

Slide 20, you will see an updated illustration of our all-in D&C costs that we discussed on the last call. We have been working diligently to keep driving down our costs, and we ended 2019 with an average D&C cost of $1,136 a foot. This is down $287 a foot or 20% from our year-end 2018 cost of $1,423 a foot.

The soft frac market continues to be the main driver, pushing our costs lower, but we're also seeing improved completion efficiencies, partially as a result of pumping less fluid and heating faster cycle times.

With several of the current wells that are in progress, we've started testing some smaller job designs. And so we anticipate that our average D&C cost will decrease even further through the first half of 2020.

That summarizes the operations. I'm going to turn it back over to Jay to wrap things up.

All right. Thank you, Dan. Thank you, Roland, and the other 205 employees who created those 2 numbers that those 2 men gave.

If you go to Slide 21, we summarize our outlook for this year, This year, we are primarily focused on free cash flow generation and managing the company through the current low natural gas price environment. Our Haynesville drilling program generates economic returns, even with the low natural gas prices that we currently live in. We have cut back the number of wells we're drilling in order to generate free cash flow that we will use to pay down our debt and strengthen our balance sheet.

The strength that we have is our industry-leading low-cost structure and our well economics. We still expect 6% to 8% pro forma production growth in 2020, even with the reduced activity. We've prioritized free cash flow goals in 2020 over production growth, but have maintained adequate investment to keep our production flat on a longer-term basis. We have hedged almost half of our production for the next 12 months and have adequate liquidity of $269 million, as Roland reported.

The last slide, Page 22, is really for the modelers. If you go to Slide 22, we could give financial guidance for the year for all the modelers out there. Our total 2020 production is expected to average 1.25 to 1.45 Bcf per day, of which 97% to 99% is expected to be natural gas.

Our lease operating costs are expected to average $0.23 to $0.27 per Mcfe in 2020. Our gathering and transportation costs are also expected to average $0.23 to $0.27 per Mcfe in 2020. Our production taxes are expected to average $0.06 to $0.08 per Mcfe. Our DD&A rate is expected to average $0.85 to $0.95 per Mcfe. And our cash G&A is expected to average $0.05 to $0.07 per Mcfe.

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

(Operator Instructions) Our first question comes from Dun McIntosh of Johnson Rice.

Congrats on another strong quarter. Dan, maybe for you, just going back to Slide 20. There's some very impressive improvements you made over the past year on cost per foot. I was wondering if you have kind of an idea of how much further you may be able to drive those down and what the implications could be for your current 2020 budget of about $420 million.

It kind of depends really on how much smaller we go on all of the frac jobs in 2020. But we're testing some of the smaller jobs. Those are primarily on the infill locations, where we're kind of doing the full development up around the Greenwood-Waskom area. And so if we just keep pumping the current size jobs and keep doing what we're doing, we're still probably looking at another $50 a foot. We can go down about another 5%. But if we push forward with some of these smaller jobs that we're testing, I mean, we could go a little bit lower than that. So if we say, for every $100 a foot that we save, that's going mark us down approximately $30 million less on our budget numbers for 2020.

All right. That's good to hear. And then maybe just kind of around the '20 program. It came at the end of '19. It's about 9 rigs. And now you're going to 5. Wondering if we could just get some more color around kind of CapEx cadence and production cadence over the course of '20. And I know it's probably a little early for '21, but kind of how you see yourself exiting '20 going into next year.

So we should be just slightly single-digit growth this year with the 5 rigs. We currently have 6. We'll be dropping the 1 rig probably early next month sometime. We should be exiting 2020 with slightly higher production than we've got currently. 2021 is probably a little bit far off to really forecast how many rigs we're going to be running. But I would say that at a minimum, we would be continuing to want five rigs and maybe six rigs.

Yes, I think what we do on that, I mean, since we're in such a volatile glut of natural gas, we don't know where the prices are. I mean, every quarter, we want to give you a profit. Every quarter, we want to give you free cash flow. We'll toggle our CapEx to give that to you. And then the beauty of this, I mean, again, [95%] (corrected by company after the call) of all the inventory we have HBP'd. We can toggle this back. We can grow it in a hurry or we can pull it back in a hurry. And if you look even at the rigs we have, when you give a 60-day notice, we probably don't have any rigs. So we don't have any long-term commitments there on the service side. And if you look at the firm transportation or minimum volume commitments, I mean, they're almost 0.

So we have that managed, but quite frankly, to be in a soft market that we're in today. So we just have to give you -- again, we have to act right and we're to give you the numbers that you'd be pleased with, that we'd be pleased with in 2021, that is do we keep at 5 rigs, do we drop it to 4, do we add a sixth rig. But the beauty is we can do all of those things. And hopefully, you'll trust that we'll make the right decision.

That's good to hear. And then if I could sneak one more in. Knowing that you've been active obviously with the Covey Park acquisition and a couple of other smaller transactions. Wondering what the A&D and M&A market is looking like given the volatility that we've had in the commodity in the past couple of months.

Well, there's a lot of energy bonds that are maturing in the next 1, 2, 3, 4 years. There's stress there. I think the borrowing basis will be stressed because I think the process will be pulled back from the banks. I think they have to be a little bit. I think the capital is very constrained. If there's any out there, I think private equity, the bets that they've made. I think that they'd like to monetize some of those if they could since they've made them 4, 5, 6, 7 years ago. And I do think that we're one of the unusual kinds of partners out there because we are a public oil and gas company. And we do say that, I think, we're the only kind of public energy company our size [in the Haynesville] (added by company after the call). It has been rebirth by the belief of Jerry Jones and his family when they called us in January of '18 when they're looking at a depressed market and really acquired the ownership in Comstock when we were in tough times. Same thing happened in 2019. We acquired Covey Park when times were tough. So we've been rebirth in tough times. So that's where you look at this cost structure, the high margins and the low cost. We're public. I think a lot of the companies would like to deal with a public entity because, at some point in time, the sector will turn around, you will want somebody to be a winner. And we want to be on that winning circle. So I I think we will attract a lot of those opportunities. Now I think we're cautious because we don't want to hurt the years and years we put to get where we are. And we don't want to hurt relationships, so we're not going to get weak in a market we're in. If we do anything, I mean, it will create less leverage and it will create a stronger future. So that's what we're looking to doing.

Our next question comes from Phillips Johnston of Capital One.

Just a follow-up on the question about the trajectory of production going forward. So it sounds like you should exit this year slightly above where you are today. So I guess, you're at 5 rigs and around 34 wells for this year. So is it safe to say that's something slightly above maintenance CapEx level and a maintenance program would probably be something more like 4 to 4.5 rigs and maybe 27 or 30 wells or so?

I think that's a pretty good number. I mean, we looked at -- we give you a 6% to 8% production growth this year. Now we come off a strong fourth quarter, as Roland said, with 9 rigs. We've got some kind of torque in the very first. But I mean, we're looking at -- we don't want production to drop. We want to stay flat and maybe grow a little bit. We always want to protect our borrowing base, assuming that the prices may come down a little bit. So Roland, you may want to add to that.

Yes, I think that's correct. I think closer to 4 operated rigs is probably that maintenance level of keeping kind of production and reserves flat. So we're just slightly above that with the 5 rig program. And yes, we'll continue to look at whether we want to keep 5 rigs running. I mean, that's something that we can change. We can change the program and trim it back or within about 30 or 60 days of making that decision. So we will continue to monitor that, obviously, with a very weak gas prices that are out there kind of compounded by this ery disappointing winter for people like us in the natural gas business.

Phillips, there's probably, say, 5 months ago that we said we're going to drop from 9 to 6 rigs by January 1, and we did. We're at 6 rigs January 1, 2020. So -- then we said, "Okay. Do we need to drop to 5?" And the answer is yes. So we're at 5. And then, like Roland said, if we need to drop it to 4, we can. We can do that. We've got a pretty decent hedge book. I wish it were a little stronger. It's not. It is what it is. It's about half [of our production at $2.66] (corrected by company after the call). So -- but then, if you look on the inside, and then your question is how many rigs, I mean, our costs have come down 20%. That's a big number. We think maybe they can come down another 5%. The quality of these wells have been better than we -- we've predicted, strong results. And I think that's what encourages the Jones family to say, "You know what? We made a big bet in January of '18 and we see today that all those wells, 217 of them, those wells look really good. It's as good or better than we thought."

And we're in a soft market. We didn't project that we'd be in a super strong market. We thought it would be soft for a while. That's one of the reasons, you've got a really great marriage of the Covey and Comstock because we thought we had to have that marriage end up with the results we have today because, stand-alone, I don't think either company could gain this type of result. So it's a good thing. We appreciate your support.

Yes. Okay. And Jay, I guess, you also mentioned protecting the liquidity on the RBL. What are your expectations going into the next redetermination?

Well, you never know the outcome. I mean, we think it will be favorable. But the thing we do have, I think we have 18-or-so in our group, and we've dealt with 16 of the 18 before. It is a new banking group. It's not like they've been around 10, 20, 30 years (inaudible) and they got back into the facility, with a $1.5 billion [elected commitment] (added by company after the call) and a $1.575 billion borrowing base. So it's new. I think the second thing is we're profitable. I think the third thing is we have free cash flow, and that extra free cash flow will go to pay down what we've drawn down. So those are 3 positive things I think that a lot of the companies don't have. And then I think we come in and they have to see if we did what we told them we'd do, and we have. And I think our reserves look strong. Our well performance look strong.

I think that's the key thing is that we did add a lot of reserves, especially in the PDP category since the last [borrowing base] (corrected by company after the call) redetermination. We'll obviously be using lower price decks that are out there in the bank market. And we are very mindful of the bank market is very soft. But we kind of think we'll hold our own to this cycle. As a matter of fact, we're going to try to get that over with and done in March, so we'll try to really get that kind of settled in the early part of the redetermination season.

Yes, we thought it would be better for the company and the stakeholders to go ahead and get through that process. So kind of the middle of March, we'll have our bank meeting. By the end of March, we hope to be out of that because we do think our numbers look strong enough to get through that early.

And given the well results -- and the good thing is even though you're using lower prices, I mean, the wells are still creating a lot of value, even at a low gas price because of our very low-cost structure. And I think that's a positive. And a lot of the basins can't do that in this really low gas price environment that exists today.

That's a great point.

No, I was just going to say that's a good point. I did notice that your cash cost guidance for the year was pretty impressive, so that's certainly working in your favor. And the free cash flow in the first quarter was certainly above our expectations.

No, thank you.

We've been told by our bank that we have the very lowest overall cost structure in their gas universe of companies they lend to, so I think that will help. I mean, obviously, you will have to overcome the lower base prices. But I think the Haynesville with the tight differentials to Henry Hub and a very low-cost structure that the wells provide is the one thing that kind of stands out during this period and stands up well.

Well, Phillips, as you know, unfortunately, it is a big world now between the have and have-nots. You have to have size, you have to have profits, you have to have locations, you have to have good results. You have to have integrity. I mean -- and then the banking group decides whether they're going to have future business with you or not. A lot of that goes in the equation, too, and I think we have all those things. But that was only created since 2015, so the only reason we have that because of wells we drilled proved up to where we are.

Our next question comes from Jeffrey Campbell of Tuohy Brothers.

And congratulations on another strong quarter. Earlier in the call, you mentioned that the infill jobs are getting smaller, and I'm presuming this is to avoid interference with parent wells. First, could you identify what percentage of the 2020 program are going to be these sort of infill wells as opposed to undrilled pads getting their first completions?

Well, I'd say, as far as the 2020 program, I wouldn't say the majority of the program is infill wells. We are testing the smaller jobs where we're pumping on a few of the wells where we're drilling some infill wells in the Greenwood-Waskom area. And currently we've got 4 wells left to drill in that area, and we're going to have that area basically drilled up. So the remaining part of the program in 2020 is going to still be basically spread out across the other acreage. And depending on kind of the results we see from these smaller tests, we'll decide if we want to maybe continue pumping a few more of those.

Okay. And that's helpful. And also Slide 19 shows that there was some activity in Panola County in 2019, fourth quarter maybe. I was just wondering, do you have any plans to do any Texas Haynesville drilling in 2020?

We do have some continued drilling in Texas in 2020. I'd say it'd probably be about the same percentage that we had this year. I can't recall the number well off the top of my head.

I think it's maybe about 4 or 6, something like that.

Yes, I feel, say, 5, 6, 7 wells, I think we got planned for Texas this year.

Our next question comes from Gregg Brody of Bank of America.

Just a quick one on your cash flow. I know in the past, you've had tax refunds. I wasn't sure if you expected one this year. And then also if you're dropping the rig, do you expect any sort of working capital impact in terms of outflows from dropping the rig?

Yes, we will get around $5 million in additional AMT tax refund in this year and then again in the following year. That's really the way that the new Tax Act kind of fit in the overall refund when they eliminated corporate AMT. So not as large as the $10 million that we got in 2019.

And then, obviously, working capital will adjust. With the lower activity, you'll have some working capital use of the cash flow. It will be spent a little bit less on CapEx. With the acquisition coming in, in the third quarter, you had quite a bit of cost related to the acquisition. The thought of that has kind of settled out as you got into the fourth quarter. But obviously, a lot of changes in the company's overall balance sheet with a much larger base.

Are those impacts in your free cash flow estimate? I think you said the $150 million to $200 million.

That's all an accrual number.

Our next question comes from Welles Fitzpatrick of SunTrust.

Am I correct in thinking that all the wells on Slide 19 are Haynesville? And can you talk to any plans to do any Bossier tests in 2020?

All of the wells that are on Slide 19 are Haynesville wells. We do have some Bossier wells planned for, I think, in early '21, not in 2020. So I mean with the current prices where they are and these market conditions, we're drilling the better acreage. So I mean, the Haynesville, across the board, obviously, is better performing than the Bossier, so that's kind of where we're going to be concentrating in 2020 still.

Okay, okay. Makes sense. And then can you talk to the George Mills well? Obviously, it was a little bit better than the rest around it. Anything different on the completion there? Was it unbounded? I mean, is there anything that we should look for with that kind of outlier performance?

Well, obviously, the acreage over at (inaudible) is core acreage. There's really good rock over there. The George Mills was relatively unbounded, didn't have wells on either side. We did spend a little bit more money on our flowback rig up to where we could flow that one a little bit harder, got the 45 million a day IP. I mean, it's held up really well since then. But I mean, all of the acreage over in that area certainly has the potential to deliver those kind of results. I kind of answered your question. I mean, it was unbounded. It was not a lot of group of wells.

(Operator Instructions) There are no further questions. I'd like to turn the call back over to [Jay Allison] (corrected by company after the call) for any closing remarks.

This is Jay. I was thinking, for some closing comments, all the E&P companies, energy companies have kind of been in a foxhole now. I mean, we are. It's a pretty terrible market. Maybe the overall market is. But everything starts and ends with our relationships, and that's the listeners on this call. I mean, you obviously are in our foxhole, period. So perseverance and hard work is what we'll continue to give you, period. That's the cloth we're made of. The trial that we're in provides us with the opportunity to do better, quite frankly. (Inaudible) Our team's energy is renewed daily, and that's the chemistry of this team, that's the results that we gave you today. That's result of the Covey combination with Comstock.

So again, I want to close, I want to thank you for your time. It might be the most valuable thing you have. We know it's valuable, so thank you for the entire 45, 50 minutes of your time today. So we'll keep serving you. Thank you. Michelle, thank you.

You're welcome. Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect. Everyone, have a great day.