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Comstock Resources, Inc. (CRK) CEO Jay Allison on Q3 2019 Results - Earnings Call Transcript

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About: Comstock Resources, Inc. (CRK)
by: SA Transcripts
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Earning Call Audio

Comstock Resources, Inc. (NYSE:CRK) Q3 2019 Earnings Conference Call November 7, 2019 11:00 AM ET

Company Participants

Jay Allison - Chairman & Chief Executive Officer

Roland Burns - President & Chief Financial Officer

Dan Harrison - Vice President, Operations

Conference Call Participants

Don McIntosh - Johnson Rice

Janet Chenoweth - Stifel

Jeffrey Campbell - Tuohy Brothers

Gregg Brody - Bank of America

Operator

Ladies and gentlemen, thank you for standing by and welcome to the Comstock Resources Inc. Third Quarter 2019 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions]. I would now like to hand the conference to your speaker today, Jay Allison, Chief Executive Officer.

Jay Allison

It's a rainy day in Dallas. So it's a good day to have an earnings call straight out like that. 21 months ago, where Jerry Jones reached out to Comstock, he saw something. Over the last 21 months, our goal has been to be the lowcost producer and have the highest margins at the same time right-sizing. The company have to be competitive in the new era of energy that we're in. The corporate report we gave you today is a good marker to where 209 employees of Comstock have taken the company in a very short timeframe. We will report today on a company that we bought for all stock during the last quarter, which is a nice positive statement towards our consolidation goal, our quality assets with no added leverage. The energy sector needs this type of freshness in the company that focuses on less corporate over add, zeros in on shareholder's return and honors those that have provided financing. I can assure you that Jerry Jones who owns 75% of Comstock, continues to use his time, talent and money to continue to create the company, you are compelled to own a piece of and support.

Thank you for joining us today. We never take your time for granted. Welcome to the Comstock Resources Third Quarter 2019 Financial and Operating Results Conference Call. Today we will review our third quarter 2019 earnings and drilling results as well as update you on our acquisition of Covey Park Energy, which was closed on July, 16. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation titled Third Quarter 2019 Results. I'm Jay Allison, Chief Executive Officer of Comstock and with me is Roland Burns, our President and Chief Financial Officer and Dan Harrison, our Chief Operating Officer.

Please refer to Slide 2 in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you go to Slide 3, the 2019 third-quarter summary. On Slide 3, we cover some of the highlights of the third quarter.

For much of the third quarter, we were very focused on the transformative Covey Park Energy acquisition, which we closed on July, 16. Combining Comstock and Covey Park created the basin leader in the Haynesville Shale, which is the premier natural gas basin in North America with superior economics given its geographic proximity to the Gulf Coast. The third-quarter results included the operations of Covey Park for 77 days.

Our Haynesville and the Bossier shale drilling program continue to deliver strong production growth. Comstock and Covey Park have drilled and completed a combined 201 operated wells since 2015, which have an average IP rate of 23 million cubic feet per day. The wells we completed in the third quarter average 25 million cubic feet per day. Our combined performance of Haynesville shale production in the third quarter was up 34% from the third quarter of last year. We have also been driving down our well cost in Haynesville. Our latest well cost per lateral foot was 19% lower than what we averaged in the fourth quarter of 2018.

The strong natural gas production growth was all set by weaker natural gas process in the third quarter. For the quarter, we reported oil and gas sales of $251 million, adjusted EBITDAX of $189 million, operating cash flow of $143 million or $0.60 per share and adjusted net income $34 million or $0.17 per share.

Slide 4, if you'll flip there, is a good summary of the Covey Park Energy acquisition. The combination created a company with substantial scale in the Haynesville. We produced over 1.2 billion cubic feet of natural gas equivalent per day and have 5.4 TCFE of SEC proved reserves and 309,000 net acres in the Haynesville.

We have more than 2,000 net drilling locations, which gives us over 30 years of inventory and our planned 2020 activity level of six operated rigs. Our third-quarter pro forma unit cost structure is only $0.66 per Mcfe, which is one of the lowest in the industry and our third-quarter pro forma EBITDAX margins of 74% is one of the highest in the industry.

With the merger closed, we materially changed our leadership team with half our department heads coming from each company. Our department heads are selecting best practices from each company and have put together their teams with a focus on creating an efficient, low overhead company with favorable proximity to the Gulf Coast demand and over 500 miles of owned gas gathering infrastructure. We have higher natural gas price realizations. The Covey Park assets achieved higher gas price realizations in Comstock and we currently renegotiated new gathering contracts and marketing arrangements to give us greater access to the premium Gulf Coast markets.

We will complete the consolidation of the Dallas area corporate offices later this month and have implemented a 41% reduction in the combined corporate staff. We're targeting go forward annual G&A of $30 million, which is about half of the combined annual G&A of the two companies of $61 million in 2018. With the merger, we have added data science to the staff and implemented a tailored drawdown for every new well, which we feel will further improve the economics of the Haynesville wells.

Lastly, we are very focused on the balance sheet as we should be. Our leverage metrics immediately improved as a result of the transaction. As Roland will go over later, we have reduced our planned drilling activity to six operated rigs in 2020. This will protect our balance sheet and liquidity and ensure we can hit our target to generate free cash flow in 2020 of over $200 million. We will also consider potential divestitures of our non-core assets in order to pay down our debt and improve our current liquidity.

If you go to Slide 5, it's a - our bolt-on acquisition. On November 1, we closed a $31 million bolt-on acquisition of a private Haynesville shale company as shown on Slide 5. We issued 4.5 million shares in an all-stock acquisition. The properties were primarily in DeSoto Parish, Louisiana as shown on the map and include 3,000 net acres and 75 gross or 20.1 net producing wells. You can see how well the properties fit without existing properties. 36 gross or 11.7 net wells are Haynesville shale wells. 50 gross or 16.7 net wells either operated or will be operated by us. The properties are producing approximately 12 million cubic feet per day and have 89 Bcfe in proved reserves with an SEC PV 10 value of $51 million. We have identified 44 gross or 12.7 net future drilling locations on the properties.

So now, I'll have Roland cover the financial results in more details. Roland?

Roland Burns

On Slide 6, we show the combined Haynevilles/Bossier production of both Comstock and Covey Park. Third-quarter combined production of 1.1 billion cubic feet per day, has increased 34% from where the two companies were in the third quarter of 2018. Production was relatively flat on a combined basis in the second quarter rate. It has only turned 8.6 net wells to sales during the third quarter after adding 14.2 net wells in the second quarter and 18.2 net wells in the first quarter this year. However in the fourth quarter, we expect our Haynevilles/Bossier production to increase over 10% of the third quarter rate as we currently expect to put 19 more net wells on production before the end of this year.

Slide 7 recaps the production we had set in for the quarter and we are pleased to say that our third quarter shut-in volumes decreased to 3% as compared to 4% we had in the second quarter of this year. Substantially all the shut-ins were due to offset frac activity.

On Slide 8, we detail our producing cost per Mcfe. Our operating cost per Mcfe failed to $0.59 for the third quarter as compared to the second-quarter rate of $0.68 and that was all due to the Covey Park acquisition. Our gathering cost averaged $0.23. Production taxes averaged $0.07 and the overall field-level operating costs were $0.29 per unit of production. We expect to continue to improve our gathering costs with new contracts that we've negotiated or are currently negotiating and we also expect to see additional efficiencies in our field-level operating costs as we continue to integrate the Covey Park operations into Comstock.

On Slide 9, we detail our corporate overhead per Mcfe. Our G&A cost per Mcfe fell to $0.07 in the third quarter as compared to the second quarter at $0.14 and our first quarter rate at $0.19. So one of the more significant benefits of the merger is the improvement of these metrics due to reduction of personnel that we had in the few organizations, enable to [indiscernible] in the same basins and in the same city. With this very low overhead, we now have the lowest cost structure in the industry among public companies. In our merger, I think, it's a great example of the benefit of combining the two best shale operators in the same basin and the value that can be created from such a combination.

On Slide 10, we detail the depreciation, depletion and amortization per Mcfe produced. Even though this is the non-cash number, it's kind of - points to an aggregate way of what you finding cost has been over a long period of time. This non-cash expense decreased to $0.79 per in the third quarter and this is compared to the $1.04 we were in the second quarter of this year and the $0.99 that we were in the first quarter.

On Slide 11, we summarize the third quarter financial results that we reported today. Our production in the third quarter was 100.9 Bcfe. That includes 603,00 barrels of oil. This is 245% higher than the third quarter of 2018 and 124% higher than our second quarter. As it - that now includes the Covey Park operations for just 77 days of the quarter, oil and gas sales including realized hedging gains were $250.5 million or 143% higher than the third quarter of last year. We did - you can say that weaker oil and gas prices in the quarter did offset some of the impact of the significant production growth. In this quarter, our realized oil price was $51.27 per barrel. Our realized gas price was $2.26 per Mcf including the benefit of our realized hedging gains.

But overall, our average natural gas price realization was down 15% from the third quarter of last year. Our adjusted EBITDAX came in at $189 million for the quarter and this is a 146% higher than the third quarter of 2018. Operating cash flow was at $143 million, up 178% from 2018. We did report on net loss of $1.3 million for the quarter or $0.01 per share. But this includes many unusual items that are not part of ongoing operations. If you exclude those items, our adjusted net income was $34.3 million or $0.17 per diluted share. These items - net of the related income taxes would include $28.7 million of merger-related cost, $3.2 million of the realized Covey Park hedge gains that related to the period July 16 to July 31 that were settled before the merger closed. So this - that included in the realized gains that we included in the financial statements. A $2.9 million in discount amortization resulting from adjusting the Covey Park bonds to the market value it closed. So that the amortization of the interest relating to that. And then we had an unrealized mark to market loss [Technical Difficulty] $8 million in the quarter.

On Slide 12, we summarize our financial results for the first 9 months of this year. Our production for the first 9 months was 184 Bcfe and that included 2.1 million barrels of oil and this is about 148% higher than the same period in 2018. Our oil and gas sales including realized hedge gains were $513 million, 114% higher than the same period in - last year. Oil prices in this period averaged $49.44 per barrel. Our realized gas price averaged $2.39 per Mcf including realized hedge gains. In our 9-month basis, our overall natural gas price realization was down 12%. Adjusted EBITDAX was $379 million at 117% higher than last year. Operating cash flow was $280 million, 146% higher than last year and we reported net income of $33.6 million for the first 9 months of this year or $0.26 per diluted share. Our [Technical Difficulty] net income for the items that we talked about, a lot of it relating to the merger. Our adjusted net income for this period was $71.2 million or $0.51 per diluted share.

On Slide 13, we present our operating results and just pro forma for the Covey Park acquisition for all of the third quarter and all of 2019. So pro forma production for the third quarter was 111.5 Bcfe and oil and gas sales would have been $282 million. The pro forma natural gas price for the third quarter after we had closed the acquisition on July 1 instead of July 16, would have been $2.33 per Mcf including realized hedge gain. In pro forma production for the first nine months of this year, as if we'd closed the acquisition on January 1, was 329.7 Bcfe with oil and gas sales including hedging gains of $904 million. And the pro forma natural gas price for this 9-month period would have averaged $2.55 per Mcf.

On Slide 14, we summarize the hedge positions we have in place for our oil and gas production and obviously those hedges were very contributed to the really good quarter we had in the third quarter because we had very, very low gas prices during that quarter. For the remainder of 2019, we have about 702 million cubic feet per day of our gas production hedged and about 3,100 barrels of our oil hedged. And the going into 2020, we have 488 million cubic feet of our gas hedged and 3,100 barrels of our oil hedged. Yes, these numbers are all on a daily introduction basis. We recently added 100 million cubic feet of gas swaps for 2020, which had a weighted average strike price of $2.53 and sold gas - natural gas swaptions totaling 80 million cubic feet of gas per day for 2021 at a weighted average strike price of $2.54. And our plan is always - is to have 50% to 60% of our production hedged for the upcoming 12-month period and we continue to roll that forward in a 12-month period basis.

On Slide 15, we highlight some of our midstream and marketing initiatives, which has resulted in the gathering - really it resulted in the lowest gathering cost in the basin at $0.23 per Mcfe. And it also helps us limit our basis risk to the regional hubs by having a gas price directly off Henry hub or other premium Gulf Coast indexes. We also have access to an extensive gathering and transportation pipeline net well, which helps us have low gathering cost including 500 miles of our own owned gathering. We recently have entered into an agreement with Enterprise Products Partners to be a major shipper on its new 1Bcf per day Haynesville Acadian Extension, which will take our gas to the Gillis hub. At the same time, we've also entered into medium-term sales agreements for that gas, to price that gas based on the premium Gulf Coast indexes. And yes, another aspect to our strong price realizations and low gathering coast is that we have no unmet minimum volume commitments and we have very low exposure to out-of-the-market or above-market gathering contracts, which are very prevalent in our basin and many of the other natural gas basins.

On Slide 16, we recap our spending in the first 9 months on our drilling and development activity and it looked - we expect to stand for all of - for the rest of 2019 and we're going to give you a first look at our budget for 2020. So far this year, we've spent $336 million on development activities through the end of the third quarter and of course starting on July 16, when the merger closed, we are running nine operative rigs in the Haynesville. So $336 million of our total spending was in the Haynesville shale program. We drove 41 or 28.8 net wells, operated wells and we also completed eight operated and 11 non-operated wells or 5.2 net wells that we have drilled back in - last year. In addition to the Haynesville, we spent $16 million drilling four or 2.2 net Eagle Ford oil wells, which we're producing during the quarter and we spent $3 million on our Bakken properties.

For the entire year of this year, we're estimating now that we'll spend $500 million on capital activity and we expect to reduce our rig count to six operated rigs as Jay mentioned earlier by early next year. With this six rigs program that we're currently lining up for next year, we expect to spend $475 million on drilling and development activities and almost all those dollars are going to Haynesville and we estimate that we'll [Technical Difficulty] 62 or 44.4 net operated Haynesville wells next year. With this lower rig count, we expect to be able to generate significant free cash flow and our goal is to have that in excess of $200 million for next year and that's - we think that's achievable even with the current low natural gas prices that are out there at this current time. So we're definitely - we're going to prioritize the free cash flow over production growth but we do expect, given the high level of activity that we've had in - this year, that we still will have production growth of 6% to 8% in 2020 and that - we're measuring that production growth from 2019 on a pro forma basis. So production growth as combined companies of 6% to 8%.

We've also included on this slide, some additional guidance numbers for the analysts that follow the stock for both production and cost estimates both for the fourth quarter and for what we see for next year.

On Slide 17, we present a balance sheet at the end of the third quarter. We had $53 million in cash and $2.7 billion on total debt, which was comprised of the amount outstanding under a 5-year credit facility and $1.475 billion in Senior Notes. We have no debt maturities until 2024 and those Senior Notes maturities until 2025 and 2026. And our preferred stock has no maturity. We ended this quarter with $288 million in liquidity and again, with part relation of free cash flow, we just don't see use of that liquidity and continue to grow that liquidity as we achieve our goals for the combined company. Looking at equity, we had - we ended the quarter with common equity of $1.1 billion and preferred equity of $385 million. On the balance sheet, you'll see that we have $375 million of preferred equity booked. It's not a typo, the difference is, market valuation discount that we had to apply to these series of preferred that we issued in the Covey Park acquisition. The face value of that preferred - of our total preferred outstanding used is $385 million.

So with all that, I'll turn it over to Dan to kind of report on the drilling results.

Dan Harrison

If you flip over on Slide 18, you'll see the new acreage map, which highlights on this 309,00 net acres position, which is a result of the Covey Park acquisition and our small recent bolt-on acquisition that closed on November 1. Since reentering the play in 2015, we, including Covey Park now drilled and completed 201 operated wells with an average IP rate of 23 million cubic feet a day. To-date in 2019, we have drilled 41 gross operated wells and plan to drill a total of 65 operated wells by year-end with an average lateral length of approximately 8,000 feet. These wells have been and they continue to be very successful.

On Slide 19, this is a locator map showing where we have our focus of activities since our last call. Since the last date, we have now turned an additional 23 wells to sales. As you can see, the majority of the activities is going to concentrate mostly up in the northern portion of our acreage. All but one of 23 wells were drilled as long laterals with the completed links ranging from 5,450 feet up to 11,361 feet with an average lateral length of 9,343 feet. The wells were completed with sand loadings ranging from 3,000 pounds per foot to 3,800 pounds per foot and a cluster spacing ranging from 15 feet to 40 feet. The average jobs saw for all the wells was 3,550 pounds per foot and 21 foot cluster spacing. The initial production rates range from 19 million cubic feet per day up to 32 million cubic feet per day and with an average IP of 25 million cubic feet per day. We have about ten additional wells that are in the process of being completed.

Over on the next slide, this illustrates the results of our ongoing efforts to reduce our on all our D&C costs. From 2018 to 2019, we see year-over-year reduction of 12% in our D&C cost. Since the end of 2018, we've cut our D&C cost from $1,445 of trade down to $1,176 a foot, which represents the reduction of $269 per lateral foot or 19% savings. The obvious factor driving our cost lower has been the soft right market including the [inaudible] pressure on local sand prices and complemented by drilling our longer laterals and our improved completion efficiencies. In the near term, we do anticipate this trend will continue to go down slightly. We're also evaluating, testing some slightly smaller frac design in the near future that can reduce our well cost further and we feel very confident that we can execute these jobs while maintaining our current level of well performance.

On Slide 21, this is our Haynesville/Bossier drilling inventory. As of the end of the quarter, a total gross operated inventory now stands at 2,396 locations. Our average net interest to 76%, which equates to 1,817 net operated locations. The gross operated inventory has been split up between short laterals of less than 5,000 feet, medium laterals of 5,000 to 8,000 feet and long laterals greater than 8,000 feet. So within our gross operated inventory, we currently have 617 short laterals, 918 medium laterals and 861 long laterals. 61% of gross operated locations are in the Haynesville and the remaining 39% are in the Bossier. In addition to our operated inventory, we have 1,475 non-operated locations with an average net interest of 13%, which represents another 193 net non-operated locations.

This extensive inventory provides the company with over 30 years of drilling locations based on our forecasted 2020 activity level. Repeating what we said on past calls, we will continue to pursue acreage trades when possible to consolidate our core acreage position and enhance our lateral lengths. With that summarizes of the third, I am going to turn it back over to Jay to wrap things up.

Jay Allison

If you'll look at the 2020 outlook, turn to Slide 22, we'll summarize our outlook for 2020. It's pretty exciting, I mean, for the rest of this year, our primary focus is to complete the integration of Covey Park into Comstock. Our goal is to have this substantially completed by year-end and it is going, I must say, really well as I discussed earlier. We're confident that we'll deliver all these substantial values value-adding synergies of the combination of the two best Haynesville shale operators can offer. Our Haynesville drilling program continues to generate economic returns even in the low natural gas price environment that we live in today. Combined with Covey Park, Comstock now has the industry-leading low cost structure and natural gas well economics. The drilling program is delivering, as Dan said, production growth this year and we're sure to continue growth in 2020 despite a lower, intentional activity level.

Our natural gas production is expected to average 1.25 Bcf per day to 1.45 Bcf per day in 2020 and our oil production is expected to average between 5,000 to 6,000 barrels per day in 2020. The conservative 2020 operating plan utilizing six operated rigs in the Haynesville that will prioritize free cash flow generation over production growth will be funded internally and will allow for a significant free cash generation. Despite the lower activity level, we still expect production to pro forma basis to grow 6% to 8% in 2020 as Roland told you earlier. And we will continue to maintain and active acreage program, targeting the next 12 months production it will be on. And lastly, we will protect our liquidity, which is currently $288 million and we'll look to enhance it with our non-core asset sales potentially and free cash flow generation so we can pay down our bank debt.

Now for the rest of the call, I'll take the questions. I'll turn it back over to the operator and we'll take questions from analysts only and again, I'd like to iterate, I know there's three speakers on the call today, but there's 209 employees that make up this company and the board and you are backers.

So with that, I'll turn it over for questions.

Question-and-Answer Session

Operator

[Operator Instructions]. Our first question comes from Don McIntosh with Johnson Rice.

Don McIntosh

First off, congrats on the integration to Comstock and then it's pretty excited on that moving forward. First question comes with - seems like you're still active with bolt-on, I'm just wondering what that environment looks like in the Haynesville. Are there - is that a pretty good deal for all the smaller deals and then how are you all thinking about, maybe, larger acquisitions as you grow, going forward.

Jay Allison

I think on the - all the acquisitions that we listed out; we've been in the Haynesville for [indiscernible]. We've got a lot of good will in the area. We got some companies that have reached out to us and we're very cautious on making sure that it's a good - but perhaps as you can see, that's a perfect footprint for us that we're involved in the wells - so that's why we might be buying and then we do add some acreage locations and particularly if there are extended laterals. We added about 13 extended laterals. This particular acquisition is something that probably we've been looking at, maybe for 4, 5 years. Even before the sector got revived back in '15, '16, '17 as for the Haynesville. So it was a great check. If you needed a company that we bought, so there - two or one people in the Haynesville area, in the seaport area, you'd be pleased if they gave us a big checkmark on stock. They know that we're trying to reduce our debt levels, we're committed to them to look at other acquisitions like this. I think there is some more of after that are this size that [Technical Difficulty] maybe we do some, maybe we don't.

And then, as far as the larger ones, I mean, like in the opening statement, we are trying to be the company in this new area of energy, which means if we do have to have size, but at the same time, we have to continue to have our high margins at a lower cost. So I would expect in the future that you can see us continuing to take another step towards consolidating this basin, which I think we're the leader in. And it'll all make economic sense whether you're a bond owner or an equity owner or an employee. So I think you could go back to the Jerry Jones vision. Now is a rock in a tough market to have two or one asset if I make sense for the existing base of a great company we have, so you can expect us to be active.

Roland Burns

And down that add that, we as we look at unit acquisitions, large or small, I mean, one of the criteria we're really looking at is to continue and improve the leverage. It's a really important goal for us, you know, it's obviously harder to reach with low gas prices, but to get our leverage under a few times is a major goal of the company, and so transaction, like Covey Park one or this one, I mean, they're all contributing to a better leverage profile, and we don't plan to use a lot of leverage to make acquisitions. We just want to make sure everybody's aware of that.

Jay Allison

Yes, if you look at the last 21 months, every purchase we've made or consolidation we made has reduced our leverage. They've been transformed, and we become a basin later. But it has also given us our low cost structure and our oil economics, and you know, we have had and we're giving you today, I mean, we probably cut our budget for what 2020 would have looked like by $100 million. We plan on delivering these numbers with sort of operating plan, so, and it's really nice to be talking about free cash flow in a meaningful way, so we're not going to disrupt that at all.

Don McIntosh

Right. And that leads right into my next question. With your updated guidance, I don't have any trouble really getting to $200 million of free cash and so fair to assume that majority of that goes straight to the balance sheet and debt reduction or, you know, I guess, also on the tail off.

Jay Allison

Yes. Our goal is to take that pay down our debt. We need to pay down our debt. If you look at all the metrics that we needed to be able to check the box on with Covey, and I mean, Covey was in an incredibly well nice feedback company. I mean, we checked the box on all of this, except our leverage. We do need to have leverage. Our goal is to get our leverage, you know, in the 2 less than 2 range. As soon as we can do that, as prudently as we can do that. We are making big strides on that. And I'm telling you, we're going make some more big strides on that. So, yes, it's going to pay down our debt.

Don McIntosh

Okay, great thanks. And then maybe one more for Dan. When you look at the impressive cost reduction Q4 2018 did, Q4 2019 down almost 20%, what have been some of the drivers and the service costs have come down quite a bit, but what are some of the other Leverage you all have pulled to further reduce your costs in the field?

Dan Harrison

I think the obviously the frac is always and will be the big the biggest one. You know, the materials, obviously, you know, with that have come down. We've forced the completion deficiencies. We've, kind of tweaked our designs a little bit. We're just trying to increase our cycle times less days on location. The less hours that you're pumping basically is how you achieve, you know, lower call structure with your service companies. And that's probably been really the other big thing that we've done, is just, we know, we're just pumping our jobs faster. Same amount of sand but we've been pumping less barrels.

Don McIntosh

Okay, great. Well, that's it from me and congrats on a great quarter, and, the integration of Covey Park, looking forward to the next quarter.

Dan Harrison

Thank you.

Operator

Our next question comes from Janet Chenoweth with Stifel. Your line is now open.

Janet Chenoweth

Good morning. And thanks for taking my questions. My first question is on natural gas pricing. So you previously talked about your intentions to sell more gas and bid rig pricing. Could you please update us on where you currently stand on that front?

Roland Burns

Yes, the question Jane was one of our goals, it was to sell more in the mid-week or we call Index pricing. And I think we achieved that this quarter, moving almost 50-50 before to - we're really closer to 75% or so. And I think especially - with new six-rig program and a little bit less, you know, production growth, it'll be easier to do that. One of the reasons for, you know, selling in the daily market issue, not overselling your gas in mid-week and having flexibility if there's a delay and when new wells come on to sales. It'll be easier to get to a higher percentage with, especially in 2020, as the production growth rate is - comes down from the, you know, growing 20%-30% that it has over the last nine months to more of the 6% to 8% that we kind of see later on.

Janet Chenoweth

Okay, that's very helpful. A related question, so you guys have signed up for this Arcadian Expansion Project? It seems like it's scheduled for mid-2021, and correct me if I'm wrong, how should we be thinking about basis differentials for Comstock until that project is online? Should we be thinking like basis differentials being similar to 2019, any help would be appreciated.

Jay Allison

The 2021, that's a good timeframe.

Roland Burns

For service, the Gallis. And hopefully they'll beat that. But, you know, that's kind of what our expectations are. We already do have - we already before the expansion have a lot of gas in the system and we have a lot of gas that's priced on a Henry Hub basis versus a regional hub basis. So that helps out a lot. So they could - more than half our gases is priced at Gulf Coast Index, not the regional Perryville or Carthage Index. And then we're also undertaking some other measures to help – to protect us from volatility in those - in those hubs, including doing six-month sales directly to some of our purchasers where we're locking in that difference. I think as we look ahead, you know, we're comfortable with our overall new kind of weighted average differential being around 20 cents, and then as we get - hopefully as we get more and more capacity to sell directly to the Gulf Coast, we're nearing that, you know, in the future, to more of 15 cents, but I think as you look just before some of those options are open 20 cents, to maybe 23 cents. It's probably a good range for the differential.

Janet Chenoweth

That's perfect. Thank you so much. The last question, if I may, so looking at Slide 20, you obviously made the huge progress on digging and well costs, on the foot basis, I mean, could you maybe discuss how we should be thinking about well cost savings in 2020? On the foot basis as well?

Roland Burns

And to give a benchmark before Dan answers. You know, we haven't budgeted. We've budgeted the numbers that you see in our presentation. You know, not at the real attractive members we achieved in the fourth quarter, but more, about 12, 25 per foot, just to give you a framework of what, so we have some cushion there, you know, as far as what we expect in the future. But hopefully, you know, Dan could lead that.

Jay Allison

Yes, we're intentionally - because you don't know what'll happen in 2020, but we do have a bunch of work room and the numbers. Dan?

Dan Harrison

Yes. So Janet, we are going to continue to turn down slightly on those things that - as far as any big major cost reductions from the service companies, is not very likely. I mean, we'd pretty much get close to the bottom of the barrel with them, so, you know, you'll get a little bit there, but the rest of it will get from some proficiency gains. And, you know, we are going to look at, pumping some smaller jobs that will - that we think we can basically match our same well performance, which will help the rig rates. I think may inch down just a little bit more. We are - you know, I think the - just the time on location, we've basically seen that speed up. I think we'll continue to see that. I think - I think it will be a slight drop. I mean, we're already, you know, have seen several jobs that are lower than this 11.76 average. But, you know, we just need to basically do it consistently. And I think we could consistently match some of the numbers we've recently done. You know, this trend will continue to come down.

Janet Chenoweth

Thanks a lot. This is very helpful. Have a nice day.

Jay Allison

Thank you, Jane.

Operator

Thank you. Our next question comes from Jeffrey Campbell with Tuohy Brothers. Your line is now open.

Jeffrey Campbell

Good morning, Jay and Rolland and congratulations on getting that merger put together. You mentioned that you're being approached by other acreage owners. I was just wondering that some of these guys have Tier 1 acreage, but they realized that Comstock's a better operator, and that's part of a motivation to do a deal?

Jay Allison

Well, you know, these costs are $11 million to drill a completed well, and again, we reported that we built 201 of these. So you know - it's kind of a big boy game now, and you got to have some size and even 21 months ago, that's why I said, it is a new era and I think if you can, connect yourself with the Comstock like this other private company did, and you could get the synergy and it lets - you can have the appreciation like Jerry Jones did. I mean, he owns like 138 million shares stock, and the only he way makes money is if the stock goes up. So he put his money where his mouth is, and he's a big giant equity owner. So I think they've done that. I think the Jerry Jones factor is you.

I think the Jerry Jones factor is huge. I think he is totally there for us outside money. And he made his money to buy the Cowboys with oil and gas of money. So I think that synergy is very unusual. It's a depressed market. It's tier 1 well result, you can see that, and we kind of got a machine going - somebody that came in and recognized and oiled it. And I think we've got a lot of eyes here so that, you know, we've done you forever, never, never. You know, we need to perform. So, yes, I think there's a lot of opportunities out there. I think some will capitalize on and some will pass on. And like Rolland said, it's all about the leverage game now. It's not that we need, you know, more inventory.

We have over 2000 locations, but we are, you know, we are leaning forward to seeing what we can do to become a better company, more the leverage, quicker. And yet at the same time, keep what we created. So, yes, I think, there's a lot of opportunities. The basin is still a stressed basin as you know.

Jeffrey Campbell

Right. Looking at Slide 15. I was wondering, can you discuss to what extent the Arcadian pipeline insulates Comstock from the associated gas coming into the Gulf from the Permian?

Jay Allison

Yes, Roland?

Roland Burns

Well, sure. I think you look at Slide 15, you know, our major markets are probably, you know, in Louisiana side, and are as far as Permian, as you know, I think Permian Gas, you know, is going to be hitting the Gulf Coast mainly, kind of west of Houston, East of Houston, you know, there's not a lot of Gulf Coast connectivity, you know, to the Louisiana side of the market. And, you know, I think - I think the initiatives we've been taking – we obviously want to be first to market and direct a market, get to where the gas - as where is the new popular hub or where the LNG, Gulf of Mexico based chippers are going to be taking their gas, and so locking up direct transportation to it, pricing that at Gulf Coast Index, being first to market, having the lowest cost structure. That's how we think we insulate ourselves from the Permian producers. We think, though, that, you know, on the western side of the Gulf, you know, that's going to connect directly in more to the Permian.

Jeffrey Campbell

Okay, great. And if I could sneak one last thing, I just - kind of looking at the M&A the other way around. The presentation noted that there's a potential for Comstock divestitures of noncore assets to help reduce the debt and enhance liquidity. So guess what? I'm kind of thinking here. First of all, are we talking about noncore acreage within the Haynesville or outside of the Haynesville, and second of all, can you get cash - can you make cash deals in this market?

You know, bearing in mind that you're buying good acreage with stock, and it seems like M&A deals that generate cash are kind of feeling far between right now.

Roland Burns

Yes, I would agree with that. I mean that we know that - yes, M&A market is very, very soft, and capital is very hard to come by, which was driving that softness and, we don't view the divestitures of the noncore properties as a core part of our de-levering. It's just that we're open to it, giving away properties, and we're not counting on a good market there. There are properties that we will never drill in our portfolio and there are people, - their party's chasing it, and, if they can beat our price, we'd exit. Yes, we would not want to focus on that as a major source of - because we think that relying on the capital market to the M&A market. You know, you don't want to be relying on those you know in this environment and we're not in our go-forward plans.

Jay Allison

Yes. There are several kind of outreaches to us on two or three different properties that, you know, if they were to get a certain price that we're looking for, then we would divesture of that. But there are - if your ranking them core tier 1, 2, 3, tier 3, within our portfolio, these would be the tier 3. So we would get that value now. And we would - to pay down our bank debt. So we always had some divestitures potentials, if you've got a company this size.

Jeffrey Campbell

I appreciate your clarifying that again congratulations on the quarter.

Jay Allison

Yes. Thank you.

Operator

Thank you. Our next question comes from Sean Sneeden with Guggenheim. Your line is now open.

Unidentified Analyst

Good morning, guys. This is Julia [ph] in for Sean Sneeden. And, Roland, we were wondering how you guys are thinking about the fall redetermination. I know you guys went through one with a lower debt with the Covey Park field, but has debt got in materially worse? And how much of you shared with the group about free cash flow plans going forward?

Roland Burns

Sure, that's a good question. We wish we were finished with the redetermination, but because our deal was a late deal, you know, relatively speaking and put in place in July, we are in the middle of redetermination, we are highly confident that we're going to keep the boring base, is going to be - remain exactly like it is now. It will have that wrapped up in a couple of weeks. And, despite the fact that the bank price decks are lower than they were in July, we added a lot of reserves. We had a lot of PDP reserves and also since the same time frame. And we feel like, you know, that the numbers are very comparable to what they looked at then using a lower price deck and combined with a good hedge book that we have. So we'd like to have it totally finished. We do have the major banks signed off, and we just have to finish the routine process. I think you'll find it; it will be – the boring base will remain exactly where it is.

Jay Allison

Yes, we've not asked for an increase – it's a new facility. We're just asking to keep it here.

Roland Burns

And we're not even electing to use all of it right now. So but we say even without not electing all of it, we don't see, - we see it remaining exactly the same.

Unidentified Analyst

That's great, guys. Thank you.

Operator

Thank you. Our next question comes from Gregg Brody with Bank of America. Your line is now open.

Gregg Brody

Good morning, guys and congrats on a great update. Just a couple of questions, coming back to the divestiture process that you're considering, I know you said, it's some noncore assets. Is there an actual number you're trying to target in terms of how much you'd like to divest to reduce bank debt? And then you talked about some on core properties. Is there anything else infrastructural wise that could potentially be monetized?

Roland Burns

Yes, as far as other items that could be monetized. I think one of the reasons why we have the best in basin, gathering cost, and is because we haven't tried to monetize, you know, gathering assets at above market rates and create kind of off balance sheet debt. And we certainly don't do that as a good source of liquidity and not interested in doing anything that would - that would lower - that would jeopardize our cost structure. Because we think that's critical and low price times, just to be the very low cost operator, and that's what's making - that's what generates you know, good, proper results and very, very low gas prices that we have, so we really are looking at when we talked about divestitures, it's really properties, noncore properties, some we got in the merger, maybe some Comstock had that - will never ever see the drilling schedule, probably because there's so many things in front of it. And, you know, groups, you know, mainly it's reversed inquiry, it is not us marketing those. So we're not targeting a number. We're not at all and, you know, I think we recognize the weak market, and these companies that like to buy these assets, you know, have a hard time getting capital, so we're not trying to say that's a major part of our plans at all, but certainly we have those assets because we're not looking to give him away, either, because we don't think that really helps in the long run.

So - but yes, the magnitude like we said before and this is no different than what, there's no new announcement there. We said this when we closed the Covey Park acquisition. I mean, the magnitude of those is, you know, in the $100 million to $200 million range, you know, kind of a haze review, if we could get them all done, and we may get none of them done. You know, in this week, in the M&A.

Jay Allison

And several of these are carryovers from when you know Covey consolidated with Comstock, there are several properties that others wanted to buy that Covey had been talking to, which we put that on the shelf until the consolidation. And so those - now those parties are still looking at those assets. I thought something we started that we kind of inherited debt recovery. That's a good thing. And then as some of our properties have matured, we had, you know, some parties reach out to see if they could consolidate some of what we have with what they have, which would make them better, so that - that's the top things we're looking at. And it is, you know, $100 million to 200 million. You cannot count on a penny of it, and we won't give away any of it if the price is not right.

Gregg Brody

I appreciate you could be patient there, and then just you gave an update on the shut-in production on, you know, went up this porter because you're a bigger company now with Covey, What's the right way to think about that number going forward as to with the amount of production shut-in this quarter, kind of a good run rate, or was that high or low? Relative to what you think.

Roland Burns

And if I was 100%, really, because, obviously, as long as you're active, you're going to have something shut in. I think 3% is a pretty good average run rate? We obviously look - we always looked to optimize that, you know, and, I don't know if we could get it to 2% and that'd be a goal, but 3% you know, we typically model 3% to 4% when we kind of look at our future. So we thought 3% was a great number.

Jay Allison

We're very pleased with that number.

Roland Burns

A reason why that qualities are bigger because you just counting Covey now. You know, they weren't in the numbers before.

Gregg Brody

I appreciate that very much. Thank you for the call guys and the time.

Jay Allison

Yes. Thank you.

Operator

Thank you. I'm not showing any further questions at this time. I would not like to turn the call back over to Jay Allison for any further remarks.

Jay Allison

Sure. Again, you know, we're always appreciative that you take the time to listen to the complete call. We're really working hard to deliver the construct that you want and that we've got a chance to deliver to you. And we do realize it's a new era of energy. We do realize we've got to get our costs down and keep them down like we have. We do realize we have to have these high margins, and we do realize there's some opportunities out there, and we have incredible backer, which is Jerry Jones to back us. So it's a pretty fortunate cycle that we're in, and we're thankful for that. And we're thankful for all of you who are either shareholders or bondholders or you provide our bank facility or an analyst, support whatever. We're working hard, so thank you.

Operator

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.