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Comstock Resources Inc
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Ladies and gentlemen thank you for standing by and welcome to the Q4 2019 Comstock Resources Earnings Conference Call. [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 two 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 cost that created the strong results that we'll review today with you. Plus we have a very deep inventory of drilling locations around 2000 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 10000 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 managers 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 two 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. If you look on page three the 2019 accomplishments. On slide three 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 250000 net acres in the Haynesville shale with approximately 1200 net drilling locations.
We added over 700 million cubic feet a day of production and 2.9 trillion cubic feet equivalent approved SEC reserves. We successfully integrated the Covey Park operations in less than six months including consolidating the two 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 operating 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 acquisitionby issuing 4.5 million shares of common stock which added 3155 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. Our fourth quarter highlights which is slide four. On slide four 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 has done a great job at that and his team. 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 process 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 five 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 three 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 approved 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 four 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 six 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 nine net wells expected to come on production during that quarter. slide seven 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 eight we summarize the financial results for the fourth quarter of last year. Our production for the fourth quarter totaled 125 Bcfe including 577000 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 including 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 this 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 3450 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 $97 million dividend on the preferred shares. We were running a combined nine operated rigs in the Haynesville when the Covey Park merger closed. In November we announced we plan to reduce our rig count to six 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 five 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 eight 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 elective 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 four times 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 just the latest outline of our current 309000 net acre position. We currently have 1983 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 an average of 76% working interest. Our current well count increased to 217 wells turned to sales since reentering 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 871 feet. On slide 18 this is a detailed summary of our latest Haynesville/Bossier drilling inventory. This is as of year-end 2019. Our total gross operated inventory now stands at 2395 locations. Our average net interest is 76%.
This equates to 1809 net operated locations. We also have 1451 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 on average IP of 24 million cubic feet per day. The wells were drilled with a varying lateral lengths and included a large number of short laterals than the last update. The completed lengths range from 4337 feet up to 10191 feet with the average length at 6926 feet. All the wells were completed with sand loadings ranging from 3000 pounds to 3800 pounds per foot with the average at 3550 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 $1136 a foot. This is down $287 a foot or 20% from our year-end 2018 cost of $1423 a foot. The soft frac market continues to be the main driver pushing our cost 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 two numbers that those two men gave. If you go to slide 21 I direct you 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 analyst 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. Your line is open.
Morning Jay. 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.
We do so we've it kind of depends really on how much we how 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 we just with the current if we just keep upping 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 2019. It's about nine 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're going to be we should be just slightly single-digit growth this year with the five rigs. We currently have 6. We'll be dropping the one rig probably early next month sometime. We should be exiting 2020 with slightly higher production than we've got currently. '21 that probably is 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 drive 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 process 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 94% 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 farm transportation or minimum volume commitments I mean they're almost zero. So we have that group has 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 five 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 all 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 four 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. And so and I think the capital is very constrained. If there's any out there I think private equity the best 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 seven years ago. And I do think that we're one of the unusual kind of board lot 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. It has been rebirth by the belief of Jerry Jones and his family when they called us in January of 2018 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 we're I think we 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 be it will create less leverage and it will create a stronger future. So that's what we're looking to doing.
Great. Thanks for all that and congrats on a strong quarter and a good outlook for 2020. Look forward to following the story. All the good one.
Thanks for your support.
Our next question comes from Phillips Johnston of Capital One. Your line is open.
Hey, guys, thanks. 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 five 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 four 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 nine 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 prospects 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 four operated rigs is probably that maintenance level of keeping kind of production and reserves flat. So we're just slightly above that with the five rig program. And yes we'll continue to look at whether we want to keep five 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 a very disappointing winter people like us in the natural gas business.
Phillips there's probably say five months ago that we said we're going to drop from nine to six rigs by January 1 and we did. We're at six 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 at that 260 something. 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 2018 and we see today that all those wells 217 of them those wells look really good. It's 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 top 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 the thing that we have 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 it's 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 to spend. If they got back-end facility that $1.5 billion $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 three 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. So...
I think that's the key thing is that we did add a lot of reserves especially in the PDP category since the last spike 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. And but we kind of think we'll hold our own to this cycle. As a matter of fact we're going to try to we're going 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's that will help. I mean obviously you have you'll be you 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 site 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 it's 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. Your lines open.
Good morning, 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. Could you 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 there's really not I wouldn't say the majority of the program is infill wells. We are testing the smaller jobs where we're test and we're pumping on a few of the wells where we're drilling some infill wells in the Greenwood-Waskom area. And we are currently we've got four wells left to drill in that area and we're going to have that area it's going to be basically drilled up. So the remaining part of the program in 2020 is going to still be they'll be basically spread out among 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 four or 6 something like that.
Yes I feel say five, six, seven wells I think we got land for Texas this year.
Our next question comes from Gregg Brody of Bank of America. Your line is open.
Come on, guys. And thank you for all the color. 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. It's also you had 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 much larger base. But...
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.
Okay.
All right.
Thanks for that.
Our next question comes from Welles Fitzpatrick of SunTrust. Your line is open.
Hey, good morning. 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 just in the current with the current prices where they're at 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. Makes sense. And then can you talk to the George Mills well? I mean obviously it was a little bit better than the rest around it. I mean 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 is I mean that is that's 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. And so but yes I kind of answered your question. I mean it was unbound. It was not a lot of group of wells.
Okay, great. No, no, it's a strong right. Thank you guys for the time.
Thanks.
[Operator Instructions] There are no further questions. I'd like to turn the call back over to Ron Mills for any closing remarks.
This is Ron's voice. This is Jay. I was thinking for some closing comments all the E&P companies energy companies have kind of been a foxhole now. I mean we are. It's a pretty durable 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. Our team energy which people coming you've got a lot our team 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.