Ladies and gentlemen, thank you for standing by, and welcome to the Comstock Resources Incorporated third quarter 2019 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I would now like to hand the conference to your speaker today, Jay Allison, Chief Executive Officer. Please go ahead, sir.
Thank you, Joelle. It's a rainy day in Dallas, so it's a good day to have an earnings call. Start out like that. 21 months ago, when Jerry Jones reached out to Comstock, he saw something. Over the last 21 months, our goal has been to be the low-cost producer and have the highest margins. At the same time, right-sizing the company up to be competitive in the new era of energy that we're in. The corporate report we give 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 toward our consolidation goal of quality assets with no added leverage.
The energy sector needs this type of freshness in a company that focuses on less corporate overhead and zeroes in on shareholders' return and honors those that have provided us financing. I can assure you that Jerry Jones, who owns 75% of Comstock, intends 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 16th. 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 am 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 of 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 the 16th.
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 Bossier Shale drilling program continues to deliver strong production growth. Comstock and Covey Park have drilled and completed a combined 201 operated wells since 2015, which had an average IP rate of 23 million cubic feet per day. The wells we completed in the third quarter averaged 25 million cubic feet per day. Our combined pro forma 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 the Haynesville.
Our latest well costs per lateral foot are 19% 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 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 of $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 of 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 than Comstock's, and we recently 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 are 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 scientists 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're 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'll 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 five, it's our bolt-on acquisition. On November the 1st, we closed a $31 million bolt-on acquisition of a private Haynesville shale company, as shown on slide five. We issued 4.5 million shares in an all-stock acquisition. The properties are 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 with our existing properties.
36 gross, or 11.7 net wells are Haynesville shale wells. 50 gross or 16.7 net wells either are 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. Now I'll have Roland cover the financial results in more detail. Roland?
All right. Thanks, Jay. On slide six, we show the combined Haynesville Bossier production of both Comstock and Covey Park. Third quarter combined production of 1.1 million 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 due to us only turning 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 of this year. In the fourth quarter, we expect our Haynesville 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 seven recaps the production we had shut in for the quarter, and we're pleased to see that our third quarter shut-in volumes decreased to 3% as compared to the 4% we had in the second quarter of this year. Substantially all the shut-ins were due to offset frac activity. On slide eight, we detail our producing cost per Mcfe. Our operating cost for Mcfe fell to $0.59 in 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 cost with the new contracts that we've either negotiated or are currently negotiating, and we also expect to see additional efficiencies in our field level operating cost as we continue to integrate the Covey Park operations into Comstock's. On slide nine, 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. One of the more significant benefits of the merger is the improvement of this metric due to the reduction of personnel that we had in the two organizations, since we're both 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.
Our merger, I think, is 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 a non-cash number, it points to, in an aggregate way, what your finding costs have been over a long period of time. This non-cash expense decreased to $0.79 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 summarized the third quarter financial results that we reported today. Our production in the third quarter was 100.9 Bcfe, and that includes 603,000 barrels of oil.
This is 245% higher than the third quarter of 2018, and 124% higher than our second quarter, that now includes the Covey Park operations for just 77 days of the quarter. Our oil and gas sales, including realized hedging gains, were $250.5 million, or 143% higher than the third quarter of last year. You can see 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, and our realized gas price was $2.26 per Mcf, including the benefit of our realized hedging gains. 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, this is 146% higher than the third quarter of 2018.
Operating cash flow was $143 million, up 178% from 2018. We did report a 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 costs, $3.2 million of the realized Covey Park hedge gains that related to the period July 16th to July 31st, that were settled before the merger close, so just not included in the realized gains that we included in the financial statements. $2.9 million in discount amortization resulting from adjusting the Covey Park bonds to the market value at close. That's the amortization of the interest relating to that.
We had an unrealized mark-to-market loss on our hedge $28 million in the quarter. On slide 12, we summarize our financial results for the first nine months of this year. Our production for the first nine months was 184 Bcfe, that included 2.1 million barrels of oil, 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. On a nine-month basis, our overall natural gas price realization was down 12%. Adjusted EBITDAX was $379 million. That's 117% higher than last year. Operating cash flow was $280 million, 140% higher than last year.
We reported a net income of $33.6 million for the first nine months of this year or $0.26 per diluted share. However, if you adjust net income for the items that we talked about, a lot of them 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 then all of 2019. Pro forma production for the third quarter was 111.5 Bcfe, and oil and gas sales would've been $282 million. The pro forma natural gas price for the third quarter, had we closed the acquisition on July 1st instead of July 16th, it would've been $2.33 per Mcf, including realized hedge gains.
In pro forma production for the first nine months of this year, as if we'd closed the acquisition on January 1st, was 329.7 Bcfe with oil and gas sales, including hedging gains of $904 million. The pro forma natural gas price for this nine-month period would've 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, you know, to the really good quarter we had in the third quarter because we had very low gas prices, you know, 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.
Going into 2020, we have 488 million cubic feet of our gas hedged and 3,100 barrels of our oil hedged. You know, these numbers are all on a daily production basis. We recently added 100 million cubic feet of gas swaps for 2020, which had a weighted average strike price of $2.53. We sold natural gas swaptions totaling 80 million cubic feet of gas per day for 2021 at a weighted average strike price of $2.54. Our plan, as always, is to have 50% to 60% of our production hedged for the upcoming 12-month period. We continue to roll that forward on a 12-month period basis.
On slide 15, we highlight some of our midstream and marketing initiatives, which has resulted in the lowest gathering cost in the basin at $0.23 per Mcfe, and has also helped us limit our basis risk to the regional hubs by having gas priced directly off Henry Hub or other premium Gulf Coast indexes. We also have access to an extensive gathering and transportation pipeline network, which helps us have lower gathering costs, including 500 miles of our own gathering. We recently have entered into an agreement with Enterprise Products Partners to be a major shipper on its new 1 Bcf per day Acadian Haynesville 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.
Another aspect to our strong price realizations and low gathering costs is that we have no unmet minimum volume commitments. We have very little 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 nine months on our drilling and development activity, then what we expect to spend for the rest of 2019. We're going to give you a first look at our budget for 2020. Far this year, we've spent $356 million on development activities through the end of the third quarter. Of course, starting on July 16th, when the merger closed, we were running nine operated rigs in the Haynesville. $336 million of our total spending was in the Haynesville Shale program.
We drilled 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 had drilled back last year. In addition to Haynesville, we spent $16 million drilling four or 2.2 net Eagle Ford oil wells, which were 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. We expect to reduce our rig count to six operated rigs, as Jay mentioned earlier, by early next year. With this six-rig 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 will go into Haynesville. We estimate that we'll 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. We think that's achievable even with the current low natural gas prices that are out there at this current time. We're going to prioritize the free cash flow over production growth. 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. We're measuring that production growth from 2019 on a pro forma basis. Production growth of the 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 the balance sheet at the end of the third quarter. We had $53 million in cash and $2.7 billion in total debt, which was comprised of the amounts outstanding under our five-year credit facility and $1.475 billion in senior notes. We have no debt maturities until 2024 and no senior note maturities until 2025 and 2026. Our preferred stock has no maturity. We ended this quarter with $288 million in liquidity. Again, with the prioritization of free cash flow, we just don't see using that liquidity and continue to grow that liquidity as we achieve our goals for the combined company.
Looking at equity, 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, and it's not a typo. The difference is a market valuation discount that we had to apply to the Series A preferred that we issued in the Covey Park acquisition. The face value of our total preferred outstanding is $385 million. With all that, I'll turn it over to Dan to report on the drilling results.
Thank you, Roland. If you flip over on slide 18, you'll see the new acreage map, which highlights our new 309,000 net acre 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, have 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 our locator map showing you where we have focused our activity since our last call.
Since the last update, we have now turned an additional 23 wells to sales. As you can see, the majority of the activity has been concentrated mostly up in the northern portion of our acreage. All but one of the 23 wells were drilled as long laterals, with the completed lengths 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 3,000-3,800 pounds per foot, and a cluster spacing ranging from 15-40 feet. The average job size for all the wells was 3,550 pounds per foot and 21-foot cluster spacing. The initial production rates ranged 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 currently have 10 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 all-in D&C cost. From 2018 to 2019, we've had a year-over-year reduction of 12% in our D&C cost. Since the end of 2018, we've cut our D&C costs from $1,445 a foot down to $1,176 a foot, which represents a reduction of $269 per lateral foot or a 19% savings. The obvious factor driving our costs lower has been the soft frac market, including the downward 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 are also evaluating testing some slightly smaller frac designs in the near future that could reduce our well cost further. We feel very confident that we can execute these jobs while maintaining our current level of well performance. On slide 21, this is the summary of our Haynesville-Bossier drilling inventory as of the end of the quarter. Our total gross operated inventory now stands at 2,396 locations. Our average net interest is 76%, which equates to 1,817 net operated locations. The gross operated inventory has been split out between short laterals of less than 5,000 feet, medium laterals of 5,000-8,000 feet, and long laterals greater than 8,000 feet. Within our gross operated inventory, we currently have 617 short laterals, 918 medium laterals, and 861 long laterals. 61% of our gross operated locations are in the Haynesville. 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've said on past calls, we do continue to pursue additional acreage trades when possible to consolidate our core acreage position and enhance our lateral lengths. That summarizes the operations, and with that, I'm going to turn it back over to Jay to wrap things up.
All right, Dan and Roland. Thank you. If you look at the 2020 outlook, turn to slide 22, we'll summarize our outlook for 2020. It's pretty exciting. 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 on the substantial value-adding synergies that the combination of the two best Haynesville shale operators can offer. Our Haynesville shale 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 will show continued growth in 2020 despite a lower intentional activity level. Our natural gas production is expected to average 1.25-1.45 Bcf per day in 2020, and our oil production is expected to average between 5,000-6,000 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 significant free cash generation. Despite the lower activity level, we still expect production on a pro forma basis to grow 6%-8% in 2020, as Roland told you earlier. We will continue to maintain an active hedging program targeting the next 12 months production and beyond.
Lastly, we will protect our liquidity, which is currently $288 million, and we'll look to enhance it with our non-core asset sale potentially in free cash flow generation so we can pay down our bank debt. 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. Again, I'd like to reiterate, I know there's three speakers on the call today, but there's 209 employees that make up this company and the board, and then you, our backers. With that, I'll turn it over for questions.
Thank you. As a reminder, to ask a question, you will need to press star one on your telephone. To withdraw your question, press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from Dunn McIntosh with Johnson Rice. Your line is now open.
Good morning, Jay.
Good.
First off, I guess congrats on the integration of Comstock. I know that was a big feather in y'all's hat and moving forward. First question, I guess comes with, it looks like y'all are still active with bolt-ons. I was wondering what that environment looks like in the Haynesville. Is that a pretty good flow out there on these smaller deals? How are you all thinking about maybe larger acquisitions as you grow going forward?
Well, I think on the acquisition that we just announced, we've been in the Haynesville since 2007, 2008. We've got a lot of goodwill in the area. We've got some companies that had reached out to us, and we're very cautious on making sure that it's a good footprint. As you can see, that's a perfect footprint for us, that we're involved in the wells, so that one we might be buying, and that we do add some accretive locations, and particularly if they're extended laterals. We added about 13 extended laterals. This particular acquisition is something that probably we have been looking at maybe for four or five years, even before the sector got revived back in 2015, 2016, 2017, as far as the Haynesville. It was a great check.
If you knew the company that we bought, they're tier one people in the Haynesville area, in the Shreveport area. You'd be pleased that they gave us a big check mark on stock. They know that we're trying to reduce our debt levels. We've committed to them to look at other acquisitions like this. I think there are some more out there that are of this size that maybe we do some, maybe we don't. As far as the larger ones, like in the opening statement, we are trying to be the company in this new era of energy, which means that we do have to have size, but at the same time, we have to continue to have our high margins and our low cost.
I would expect in the future that you can see us continuing to take another step toward consolidating this basin, which I think we're the leader in. It'll all make economic sense whether you're a bondholder, an equity owner, or an employee. I think if you go back to the Jerry Jones vision, now is a ripe time in a tough market to have tier 1 assets if they make sense for the existing base of the great company we have. You can expect us to be active.
Dunn, I'd add that as we look at doing any acquisitions, large or small, one of the criteria we're really looking at is to continue to improve the leverage. It's a real important goal for us. It's obviously harder to reach with low gas prices, to get our leverage under two times is a major goal of the company. A transaction like the Covey Park one or this one, 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.
Yeah. If you look at the last 21 months, every purchase we've made or consolidation we've made has reduced our leverage. They've been transformative. We've become a basin leader, but it has also given us our low cost structure and our well economics, and we have had, and we're giving you today, we probably cut our budget for what 2020 would've looked like by $100 million. We plan on delivering these numbers with conservative operating plans, and it's really nice to be talking about free cash flow in a meaningful way. We're not going to disrupt that at all.
Right. 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. Fair to assume that majority of that goes straight to the balance sheet and debt reduction.
Yeah. Our goal is to take that and 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 was an incredibly well-run, nice, fee-back company. We checked the box on all of this except for our leverage. We do need to have leverage. Our goal is to get our leverage, in the less than two range as soon as we can do that, as prudently as we can do that. We've made some big strides on that. I'm telling you, we're going to make some more big strides on that. Yes, it's going to pay down our debt.
Okay, great. Thanks. Maybe one more for Dan. When you look at the field, impressive cost reduction, 4Q18 to 4Q19 down almost 20%. What have been some of the drivers there? I know service costs have come down quite a bit, but what are some of the other levers you all have pulled to further reduce your cost in the field?
I think obviously the frack is always and will be the biggest one. The materials obviously, with that have come down. As far as the completion efficiencies, we've 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 a lower cost structure with your service companies. That's probably been really the other big thing that we've done, is just we're just pumping our jobs faster. Same amount of sand, we've been pumping less barrels.
Okay, great. Well, that's it for me. Congrats on a great quarter and the integration of Covey Park. Looking forward to next quarter.
Thank you.
Thank you. Our next question comes from Jane Trotsenko with Stifel. Your line is now open.
Good morning, and thanks for taking my questions. My first question is on natural gas pricing. You previously talked about your intentions to sell more gas at bid week pricing. Could you please update us on where you currently stand on that front?
Yeah, the question, Jane, was like, one of our goals, it was to sell more in bid week, or we call index pricing. I think we achieved that this quarter, moving from almost 50/50 before, to we're really closer to 75% or so. I think especially with the new six-rig program and a little bit less production growth, it'll be easier to do that. One of the reasons for selling in the daily market is not overselling your gas in bid week and having flexibility if there's a delay in when new wells come up to sales. It'll be easier to get to a higher percentage, especially in 2020 as the production growth rate comes down from growing the 20%, 30% that it has over the last nine months to more of the 6%-8% that we see later on.
Okay. That's very helpful. A related question. You guys signed up for this Acadian 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 basis differentials being similar to 2019? Any help would be appreciated.
Yeah. The 2021, that's a good time frame.
For the in-service to Gillis. Hopefully they'll beat that. That's what our expectations are. 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. That helps out a lot. I think more than half our gas is priced off coast indexes, not the regional like Perryville or Carthage index. We're also undertaking some other measures to help to protect us from volatility 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, we're comfortable with our overall new weighted average differential being around $0.20.
Hopefully as we get more and more capacity to sell directly to the Gulf Coast, narrowing that in the future to more of $0.15. I think as you look just before some of those options are open, $0.20-$0.23, is probably a good range for the differentials.
That's perfect. Thank you so much. The last question, if I may. Looking at slide 20, you obviously made huge progress on per unit well costs on a per foot basis, I mean. Could you maybe discuss how we should be thinking about well cost savings in 2020?
On the per foot basis as well?
To give a benchmark before Dan answers, we've budgeted the numbers that you see in our presentation, not at the real attractive numbers he achieved in the fourth quarter, but more in the about $12.25 per foot, just to give you a framework. We have some cushion there, as far as what we expect in the future. Hopefully, Dan can beat that.
Yeah. We intentionally built that in because you don't know what will happen in 2020, but we do have a bunch of wiggle room in the numbers, Dan?
Yeah.
Jane, we are going to continue to trend down slightly. I do think that, as far as any big major cost reductions from the service companies is not very likely. We'll pretty much get close to the bottom of the barrel with them. You'll get a little bit there, but the rest of it we'll get from some efficiency gains. We are going to look at pumping some smaller jobs 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. I think just the time on location, we've basically seen that speed up. I think we'll continue to see that. I think it'll be a slight drop.
We've already seen several jobs that are lower than this 11.76 average, but we just need to basically do it consistently, and I think if we can consistently match some of the numbers we've recently done, this trend will continue to come down.
Thanks a lot. This is very helpful. Have a nice day.
Thank you, Jane.
Thank you.
Thank you. Our next question comes from Jeffrey Campbell with Tuohy Brothers. Your line is now open.
Good morning, Jay, and Roland, and congratulations on getting that merger put together. You mentioned that you're being approached by other acreage owners. I was just wondering, do some of these guys have Tier 1 acreage, but they realize that Comstock's a better operator as part of a motivation to do a deal?
Well, these costs are $11 million to drill a completed well, and again, we reported that we drilled 201 of these. It's a big boy game now, and you got to have some size and even 21 that's why I said it is a new era. I think if you can connect yourself with the Comstock, like this other private company did, and you could get the synergy, and you can have the appreciation like Jerry Jones did. He owns, I think, 138 million share of the stock, and the only way he makes money is if the stock goes up. He put his money where his mouth is, and he's a big John Equity owner. I think they've done that. I think the Jerry Jones factor is huge.
I think he is totally new, fresh outside money, and he made his money to buy the Cowboys with oil and gas money. I think that synergy is very unusual. It's a depressed market. It's a Tier 1 well result. You can see that. We've got a machine going, but you had somebody that came in and recognized it and oiled it, and I think we've got a lot of eyes here. We've known you forever and ever and ever. We know we have to perform. Yes, I think there's a lot of opportunities out there. I think some we'll capitalize on and some we'll pass on. Like Roland said, it's all about the leverage game now. It's not that we need more inventory. We have over 2,000 locations.
We are leaning forward to see what we can do to become a better company, more deleveraged quicker. Yet at the same time, keep what we created. Yeah, I think there's a lot of opportunities. The basin is still a stressed basin, as you know.
Right. Looking at slide 15, I was wondering, can you discuss to what extent the Acadian pipeline insulates Comstock from associated gas coming into the Gulf from the Permian?
Yes. Roland?
Well, sure. I think you're looking at slide 15. I think our major markets are probably in Louisiana side, and I think as far as Permian gas, I think Permian gas is going to be hitting the Gulf Coast, mainly west of Houston. East of Houston, there's not a lot of Gulf Coast connectivity to the Louisiana side of the market. I think the initiatives we've been taking is we obviously want to be first to market and direct to market to where the gas. The Gillis Hub is the new popular hub for where the LNG Gulf of Mexico base shippers are going to be taking their gas. Locking up direct transportation to it, pricing that at Gulf Coast indexes, 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 on the western side of the Gulf, that's going to connect directly and more to the Permian.
Okay, great. If I could sneak one last one in. Just looking at the M&A the other way around, the presentation noted that there's a potential for Comstock divestitures of non-core assets to help reduce the debt and enhance liquidity. Guess what I'm thinking here. First of all, are we talking about non-core acreage within the Haynesville or outside of the Haynesville? Second of all, can you make cash deals in this market, bearing in mind that you're buying good acreage with stock, and it seems like M&A deals that generate cash are few and far between right now.
Yeah, we'd agree with that. We know that M&A market is very soft and capital is very hard to come by, which is driving that softness. We don't view divestitures of the non-core properties as a core part of our delevering. It's just that we're open to it, but we're not giving away properties, and we're not counting on a good market there. There are properties that we'll never drill in our portfolio, and there are parties chasing it. If they can meet our price, we'd exit. Yeah, we would not want you to focus on that as a major source because we think that relying on the capital markets and M&A market, you don't want to be relying on those, in this environment. We are not in our go-forward plans.
Yeah, there are several kind of outreaches to us on two or three different properties that, if they were to hit the certain price that we're looking for, then we would divest of that. They are not our core properties at all. These are properties, like I said, if you rank them core, tier 1, tier 2, tier 3 within our portfolio, these would be the tier 3. We would get that value now, and we'd use that to pay down our bank debt. You always have some divestiture potentials if you've got a company this size.
No, I appreciate you clarifying that. Again, congratulations on the quarter.
Yes. Thank you.
Thank you. Our next question comes from Sean Sneeden with Guggenheim. Your line is now open.
Good morning, guys. This is Julia Pucillo in for Sean Sneeden. Roland, we were wondering how you guys are thinking about the fall redetermination. I know you guys went through one with a lower deck with the Covey Park deal, but has deck gotten materially worse, and how much have you shared with the group about free cash flow plans going forward?
Sure. That's a good question. We wish we were finished with the redetermination, but because our deal was a late deal, relatively speaking, and put in place in July, we are in the middle of redetermination. We're highly confident that we're going to keep the borrowing base, is going to remain exactly like it is now. We'll have that wrapped up in a couple of weeks. 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 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. 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. We think you'll find that the borrowing base will remain exactly where it is.
We've not asked for an increase either. It's a new facility. We're just asking to keep it.
Yeah, we're not even electing to use all of it right now.
Yeah.
We say even without not electing all of it, we see it remaining exactly the same.
That's great, guys. Thank you.
Thank you. Our next question comes from Gregg Brody with Bank of America. Your line is now open.
Good morning, guys, and congrats on a great update.
Thank you.
Just a couple of questions. Just coming back to the divestiture process that you're considering, I know you said it's some non-core 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? You talked about the non-core properties. Is there anything else infrastructure-wise that could potentially be monetized?
Yeah. 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 gathering assets at above market rates and create an off-balance sheet debt. We certainly don't view that as a good source of liquidity and not interested in doing anything that would jeopardize our cost structure. We think that's critical in low price times is to be the very low cost operator, and that's what generates good profit results and very low gas prices that we have. We really are looking, when we talk about divestitures, it's really non-core 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.
Groups that are mainly it's reverse inquiry. It's not us marketing those. We're not targeting a number. We're not at all, and I think we recognize the weak market and these companies that like to buy these assets have a hard time getting capital. We're not trying to say that's a major part of our plans at all, but certainly, we have those assets that could divest of, and we're not looking to give them away either, because we don't think that really helps in the long run. Yeah, the magnitude, like we said before, and this is no different than there's no new announcement there. We said this when we closed the Covey Park acquisition.
The magnitude of those is in the $100 million-$200 million range, kind of at the base review, if we could get them all done, and we may get none of them done in this weak M&A market.
Several of these are carryovers from when Covey consolidated with Comstock. There were several properties that others wanted to buy that Covey had been talking to. Of course, we put that on the shelf until the consolidation. Those parties are still looking at those assets. That's not something we started, that we kind of inherited that from Covey. That's a good thing. As some of our properties have matured, we've had some parties reach out to see if they could consolidate some of what we have with what they have, which would make them better. That's the type of things we're looking at. It is $100 million-$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.
No, I appreciate you can be patient there. You gave that update on the shut-in production, it went up this quarter because you're a bigger company now with Covey. What's the right way to think about that number going forward, was 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 it's going to be?
Yeah, you focus on the percentage, really, because obviously, as long as you're active, you're going to have something shut in. You can't. I think 3% is a pretty good average run rate. We always look to optimize that, and I don't know if we could get it to 2%, that'd be a goal, but 3%, we typically model 3%-4% when we look at our future. We thought three was a great number.
Yeah, we're very pleased with that.
Yeah.
We're very pleased with that number.
The only reason why the qualities are bigger is because you're just counting Covey now. They weren't in the numbers before.
I appreciate that very much. Thank you for the color, guys, and the time.
Yes. Thank you.
Thank you. I am not showing any further questions at this time. I would now like to turn the call back over to Jay Allison for any further remarks.
Sure. Again, we're always appreciative that you take the time to listen to the complete call. We are really working hard to deliver the Comstock that you want, and that we've got a chance to deliver to you. 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 that there's some opportunities out there that we have an incredible backer, which is Jerry Jones, to back us. 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. Thank you.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.