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Comstock Resources Inc
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Ladies and gentlemen, thank you for standing by and welcome to the Fourth Quarter 2020 Comstock Resources Inc. Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions] As a reminder, today's program is being recorded.
I would now like to introduce your host for today's program, Jay Allison, Chairman and Chief Executive Officer. Please go ahead.
Jonathan, thank you for giving us a warm welcome. As most of you know our home office is in Frisco, Texas which is just north of Dallas and today if you looked out our windows, you would think that we were in snowy Alaska or reporting from the ski slots in Colorado. In fact, Alaska is probably warmer than the recent subzero temperatures that we've seen here with the wind chill factor. Our offices have been closed for three days now and only probably four of us are here today reporting from the office.
This arctic freeze in Texas in the Mid-Continent creates challenging days in the world of natural gas. We've experienced idle frac fleets, idle drilling rigs due to the freeze-offs, as well as record demand just to keep the power on in our homes. In fact millions are still without power as we speak.
With 99% of our reserves being natural gas, which is the cleanest fossil fuel, at our world-class Haynesville/Bossier gas fields being located in close proximity to the Gulf Coast LNG market and near major petrochemical plants and close to the industrial demand corridors, I can tell you that Comstock is well-positioned to help meet the existing and future needs for predictable and reliable energy in America.
With 2020 being such a whipsaw year, I'm pleased that all 204 employees of Comstock if weren't for you have delivered solid results for the year and expect 2021 to be outstanding. Thank you for trusting us as we continue to seek to close out every day as a stronger company.
With that, I'll start the welcoming part. Welcome to the Comstock Resources fourth quarter 2020 financial and operating results conference call. 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 entitled fourth quarter 2020 results.
I am Jay Allison, as Jonathan said earlier, Chief Executive Officer of Comstock With me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer; and Ron Mills, our VP of Finance, Investor Relations is joining us on the phone.
Please refer to slide two in our presentation 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'll turn over to slide three, we will recap some, not nearly all, but some of our 2020 accomplishments. The most significant accomplishment is our successful navigation of one of the most difficult years for our industry ever. Despite realizing $1.80 for our gas and $32.36 for our oil, we still were able to turn in profitable financial results excluding unrealized hedging losses.
We completed an accretive $207 million equity offering in May which is the first natural gas common equity offering since 2016. The offering allowed us to redeem our Series A preferred stock and save $21 million per year from the elimination of dividend payments. The 41.3 million shares we issued in the offering eliminated the need to deliver 52.5 million shares in the future for the conversion of the preferred.
We also completed two successful senior notes offerings totaling $800 million to repay bank debt This increased financial liquidity from $166 million to $930 million. We also reduced our usage of our bank credit facility from 88% to 36%. We had another year of strong results from our 2020 Haynesville/Bossier shale drilling program. We drilled 55 or 46.1 net successful wells that we operate. We turned 54 or 40.9 net operated wells to sales with an average IP rate of 25 million cubic feet per day.
In 2020, we were able to lower our well cost by 16%. Our two-mile laterals, which Dan will talk about in a minute averaged $1,026 per completed lateral foot in 2020 versus $1,215 in the prior year. This allowed us to grow our proved reserve base by 3% at a low in-finding cost of $0.66 per Mcfe. Despite having to use very low prices to determine our SEC proved reserves, they grew by 3% to 5.6 Tcfe. Our reserve additions replaced 159% of our 2020 production.
If you go over to slide 4. We cover some of the highlights of the fourth quarter on slide 4. We resumed completion activities in the third quarter and our natural gas production increased by 6% from the low third quarter level, the production in the quarter was still impacted by a high shut-in level of 6.6%. Now this is mainly due to actions we took in October to shut-in 300 million a day of our operated production in response to very low natural gas spot prices.
We turned 22 or 16.4 net Haynesville wells to sales with an average lateral length of 8,899 feet in the fourth quarter. We are well-positioned for continued production growth in the first quarter of 2021 and throughout the remainder of the year 2021. Our conservative operating plan in 2021 is focused on reducing our leverage ratio by both growing EBITDAX and reducing debt.
We're targeting to generate over $200 million in free cash flow in 2021. The higher production and improvement to oil and gas prices allowed us to return to profitability in the fourth quarter. We reported oil and gas sales of $277 million. Our EBITDAX came in at $211 million and we generated $155 million or $0.56 per share in operating cash flow. Our adjusted net income for the quarter was $35 million or $0.14 per share. Lastly, we ended the year with very strong financial liquidity of $930 million.
So now I'll turn it over to Roland to cover our financial results in more detail. Roland?
All right. Thanks, Jay. On slide 5, we summarize our reported financial results for the fourth quarter of 2020. Our production for the fourth quarter totaled 109 Bcf of natural gas and 340,000 barrels of oil. This is 11% lower than production from the fourth quarter of 2019.
Our oil and gas sales including realized hedging gains were $277 million about 10% lower than 2019 due to the lower production level. Oil prices in the period averaged $44.47 per barrel and our realized gas price averaged $2.40 per Mcf including hedging gains. So overall, our natural gas prices were up 4% in the quarter and our oil prices were down a little bit.
Looking at the cost side, our lifting costs were down 11% in the quarter. And our depreciation, depletion and amortization and G&A were both down 7% in the quarter. Our adjusted EBITDAX came in at $211 million or 10% lower than 2019's fourth quarter.
Our operating cash flow was $155 million which was 18% lower than 2019 and we reported a net profit of $77.5 million for the fourth quarter or $0.30 per share. The net income for the quarter did include an $80.2 million unrealized gain from the mark-to-market of our hedge positions, which is mainly driven by the change in natural gas prices since September 30. Adjusted net income excluding the unrealized hedging gain and certain other unusual items was a profit of $34.6 million or $0.14 per diluted share for the quarter.
On slide 6, we summarize the financial results for all of 2020. Our production for 2020 totaled 460 Bcfe, which that includes 1.5 million barrels of oil. That's 49% higher than 2019's production. The increase mainly reflects the acquisition of Covey Park that we closed in July of 2019. Pro forma for the Covey Park acquisition our production increased 2% year-over-year.
Our oil and gas sales, including realized hedging gains, were $993 million, which was 21% higher than 2019. Oil prices, including hedging, averaged $40.88 in 2020, and our realized gas price, including hedging, averaged $2.07 per Mcf, which was 12% lower than 2019.
Adjusted EBITDAX for the year was $722 million, an 18% increase over 2019. Operating cash flow was $521 million, which was 11% higher than 2019. Overall, we did report a net loss of $83 million for the year or $0.39 per share, but that loss was entirely due to the mark-to-market unrealized loss on our hedge positions. Excluding unrealized hedging losses and other unusual items, we had a net profit of $49.6 million or $0.23 per diluted share for 2020.
Despite a year of very low oil and gas prices, we were able to have a profitable year, and we did not have any impairments or other write-downs of our assets which is I think an unusual compared to many other companies in our industry. That says a lot about the quality of our assets and our low-cost structure.
On slide 7 we cover our hedging program. And during 2020, we had 51% of our gas volumes hedged, which increased our realized gas price to the $2.07 per Mcf, I mentioned, as compared to the $1.80 that we actually received from selling our production.
We also had 84% of our oil volumes hedged. That increased our realized oil price to the $40.88 per barrel versus the $32.30 per barrel we actually received. Overall, our realized hedging gains totaled $134.5 million in 2020.
With the continued strength in natural gas prices, we've continued to add to our hedge book. Since we last reported earnings, we've hedged another 90 million cubic feet of our production for the second half of 2021 and another 100 million per day for the first half of 2022.
For 2021, we have natural gas hedges covering almost 900 million a day of our gas production, which is around 65% of our expected 2021 production. The weighted average floor price of our 2021 gas hedge is $2.51.
Going forward, we're primarily focused on adding to our 2022 hedge position. We continue to target having 55% to 70% of our production hedged for the upcoming 12 to 18-month period.
Slide 8, we recap how much of our production was shut-in during the last quarter, the fourth quarter. So we had 6.6% of our natural gas production shut-in in the fourth quarter, compared to the 7.2% we had in the third quarter.
As we had talked about in our third quarter call, in early October, we voluntarily shut-in 300 million a day of our production really during the first two weeks of October, due to the very low spot market gas prices.
The remaining of the shut-in in the fourth quarter is really due to offset frac activity. We also had 2% of our oil production curtailed or shut-in in the quarter, which was a -- that's a big decrease from how much was shut-in earlier in the year.
On slide 9 we detail our operating costs per Mcfe produced. Our operating cost per Mcfe averaged $0.56 in the fourth quarter as compared to the third quarter of $0.55. Gathering costs were $0.26. Our taxes averaged $0.09 and our field-level cost averaged $0.21.
The fluctuation between our lifting costs and gathering cost is related to where the new wells were completed during the quarter, but we continue to expect those costs to remain within the guidance ranges that we have been providing.
On slide 10, we detail our corporate overhead for Mcfe. Our cash G&A cost in the quarter were $0.04 per Mcfe, which is down from the third quarter, primarily due to year-end accrual adjustments. We do expect our cash G&A costs to return to a more normalized level of $0.05 to $0.06 going forward.
On slide 11, we detail the depreciation depletion and amortization per Mcfe produced. Our DD&A averaged $0.94 in the fourth quarter, about $0.01 lower than the $0.95 rate we had in the third quarter.
Slide 12 shows the balance sheet at the end of 2020. We currently have $500 million drawn on our $1.4 billion revolving credit facility and we do expect to use our free cash flow that we are targeting to generate in 2021 to continue to pay that down. We have just over $2.25 billion of senior notes outstanding comprised of $619 million of our 7.5% senior notes, due in 2025 and $1.65 billion of our 9.75% senior notes due in of 2026. With a quarter end cash position of $30 million, our current financial liquidity stands at $930 million.
On slide 13, we summarize our fourth quarter and full year 2020 capital expenditures. We spent $169 million on development activities in the fourth quarter, of which $151 million was spent on the operated Haynesville shale properties. We also spent $6.5 million in to lease new Haynesville acreage in the quarter.
For the full year, we spent $484 million on all development activities, including $410 million, which was spent on our operated Haynesville shale properties. We drilled 46.1 net operated horizontal Haynesville wells and we turned 40.9 net operated horizontal Haynesville wells to sales in 2020. We also spent another $82 million in 2020 on non-operated wells, and other development activity. And we spent a total of $7.9 million in 2020 on leasing new Haynesville acreage.
So right now, we're currently utilizing six operated rigs for our 2021 drilling program, but we do expect to drop one of our operated rigs later this year, due to the faster drilling times that we're achieving as Dan's going to go over with his operating results. Based on our current operating plan for 2021, we expect to drill 51 net operated Haynesville wells and turned about 50.5 net operated wells to sales in 2021.
At the end of 2021, we expect to have about 17.9 net DUCs to carry into 2022. We estimate our total development capital expenditures to come in between $510 million and $550 million. And we're also budgeting to spend an additional $7 million to $10 million on the leasing program. We remain focused on generating significant free cash flow and we'll continue to target over $200 million of annual free cash flow generation as we plan our drilling activity.
On slide 14, we summarize our oil and gas reserves at the end of 2020. We grew our proved reserves from 5.4 Tcfe at the end of 2019 to 5.6 Tcfe on an SEC basis at the end of 2020. Our 2020 drilling activity added 366 Bcfe to our proved reserves and we had 367 Bcfe of positive performance-related revisions driven by the strong well performance of our Haynesville wells.
The positive reserve revisions more than offset negative price-related revisions, which were 86 Bcfe that related to using the low first of the month 2020 average prices to determine reserves. Our all-in finding costs for 2020 came in at a very attractive $0.75 per Mcfe or $0.66, if you exclude the price-related revisions. Our reserves were 99% natural gas and then 36% of our reserves were developed. 95% of our proved reserves are in the Haynesville/Bossier, 2% are in the Bakken and 3% or in other regions.
The PV-10 value of our proved reserves was $2 billion using the SEC prices of $1.99 for gas and $39.57 for oil, and 67% of that PV-10 value is related to our developed reserves. Using an NYMEX reference price of $2.75 for gas and $50 for WTI oil, which is more reflective of our current price outlook the PV-10 value of our preserves increases to $4.4 billion and the quantities of proved reserves with those prices would increase to 5.8 Tcfe using that $2.75 and $50 reference prices.
In addition to those proved reserves, we have an additional 2.4 Bcfe approved undeveloped reserves, which are not included in our proved reserves as we're not currently expecting to drill those within the five year window required by the SEC rules. We also have another 4.6 Tcfe of 2P or probable reserves and 6.8 Tcfe of 3P or possible reserves for a total reserve base of 19.6 Tcfe on a P3 basis.
I'll now turn it over to Dan to cover the fourth quarter drilling results in more detail.
Okay. Thank you, Roland. If you flip over to page -- slide 15. This is going to be an outline of our current acreage position, which has now increased in the fourth quarter to 323,000 net acres. We do control the majority of acreage with a 91% operated position and have an average working interest in the acreage of 82%. We currently have 1,953 net future drilling locations identified on this acreage with 93% of the acreage currently held by production.
Since starting our high-intensity completion program in 2015 we've now turned 272 wells to sales with an average IP rate of 24 million cubic feet a day. We're currently running a total of six operated rigs. We do plan to release one of our rigs in May of this year and continue with five rigs for the remainder of the year.
We're currently running three frac crews and we anticipate running an average of just 2.2 frac crews for the full year of 2021. We currently have 25 DUCs on our schedule. We anticipate our DUC count staying in the 20 to 25 range for the remainder of the year.
Over on slide 16 this is our latest Haynesville/Bossier drilling inventory as of year end 2020. Our operated inventory currently stands at 2,214 gross locations and 1,719 net locations. This represents a 78% average working interest on our operated inventory.
Our non-operated inventory consists of 1,585 gross locations and 234 net locations, which represents a 15% average working interest on the non-operated inventory. On our gross operated locations we currently have 485 short laterals, 799 medium laterals and 930 long laterals.
If you split these out the 2,214 gross locations by zone, we have 52% of our locations in the Haynesville and 48% are in the Bossier. This inventory provides the company with over 30 years of drilling locations based on our current activity levels.
On slide 17 is a map outline and summary of the 20 new wells that we turned to sales since the last call. The new wells were mostly located on our East Texas and Southwest De Soto Parish acreage and we did have one well completed over Elm Grove acreage.
The wells were tested at rates ranging from 18 million a day up to 33 million a day with a 24 million cubic feet per day average IP rate. The wells were drilled with lateral lengths ranging from 6,751 feet up to 12,716 feet with an average lateral length of 9,288 feet. And they were all completed with 3,500 pounds per foot sand loadings on the fracs.
We drilled and completed our longest lateral ever during the fourth quarter at 12,716 feet on the Jordan 16-9-4 number one well, which is down in the Southwest Desoto Parish acreage. We are currently completing a 13,000-plus foot lateral that will be turned to sales during the first quarter and this will be our new record long well at that time.
On slide 18 and on the next three slides are the D&C cost trends for our different lateral length buckets. Here on slide 18 shows the D&C cost trend for our long lateral wells, which are wells that have lengths greater than 8,000 feet.
On our long lateral wells in the fourth quarter we experienced a 5% increase in our total D&C costs due to a 15% increase in our completion costs. This was primarily due to the resumption of pumping our larger frac design of 3,500 pounds per foot in the fourth quarter after pumping our smaller frac design of 2,800 pounds per foot in the second and third quarters.
We were able to offset a portion of our increased completion costs with lower drilling costs in the fourth quarter due to an increase in drilling efficiency. With this increase in drilling efficiency, we have reduced our drilling costs further in the first quarter and we do expect to maintain a lower drilling cost for the remainder of the year as we drive our drilling costs down to historic lows. This will help to offset the higher completion costs that we anticipate as a result of the increase in industry activity and higher associated service costs.
Since 70% of the wells we drill in 2021 will be long laterals our cost performance in this category is the major driver in the success of our drilling program.
Due to the higher drilling efficiency, we are confident that we will be able to maintain our D&C costs relatively flat in this 1,000 to 1,050 foot range for our longer laterals. Ultimately, the gas price environment and market demand for services will determine where our costs settle out in this range.
On slide 19 is the D&C cost for our medium lateral wells. These are wells with lengths between 6,000 and 8,000 feet long. On our medium lateral wells in the fourth quarter we had a total D&C cost of $1126 a foot. This represents a slight decrease of 3% from the previous quarter.
While our completion costs also increase for medium-length laterals due to resuming the larger frac design in the fourth quarter, we were able to still achieve lower D&C costs in the fourth quarter by driving our drilling costs down by 10% with our increased drilling efficiencies. Same as our long lateral wells we have reduced our drilling costs further into the first quarter of this year and expect to maintain this lower drilling cost throughout the rest of the year.
On slide 20, so this is the D&C cost trend for our short lateral wells. These are the wells that have lateral lengths less than 6,000 feet. As you see here, we've not completed any short lateral wells for the last two quarters, which is by design since these wells do have a higher cost and inferior economics compared to the longer laterals. When we do drill our short wells we attempt to drill them as part of multi-well pads with our longer laterals to reduce costs and enhance our returns.
Same as with the longer laterals on the previous two slides, we continue to substantially drive down our cost on our short lateral wells. Over the course of the last year, we have successfully converted many of the short lateral wells in our inventory to longer lateral wells via acreage trades with other operators and also with some small bolt-on acreage acquisitions. We continue to pursue these opportunities to this day where there are opportunities.
To reiterate on our operations, we are confident we can maintain our current low D&C cost structure by capitalizing on the drilling efficiencies we've been able to achieve to date and building on these going forward. These lower drilling costs will help to offset the higher completion costs that we anticipate for the remainder of the year as a result of increased industry activity and the associated higher service costs.
That summarizes things up on the operations side. I'm now going to turn it back over to Jay.
All right, Dan, Roland, thank you. If you would let's go to slide 21 where we'll summarize, what we think is our outlook for really a fabulous 2021. We remain focused on maintaining and improving our industry-leading low-cost structure and best-in-class well drilling returns.
Our inventory as Dan had mentioned, 1953 net Haynesville/Bossier drilling locations provide us with the decades of drilling inventory. Our operating plan for the year is expected to provide production growth and generate in excess of $200 million of free cash flow as Roland had pointed out.
In 2021, we're focused on improving our balance sheet as we told everybody for months and months reducing our leverage and lowering our cost of capital. With current natural gas prices, we would expect our leverage ratio to improve to around 2.5 times at the end of 2021 down from the 3.8 in 2020.
With our industry-leading low-cost structure our Haynesville drilling program generates some of the higher drilling returns in North America. We have currently hedged approximately 65% of our 2021 production to protect our high drilling returns. We have very strong financial liquidity of that $930 million.
So with that I want to turn it over to Ron that he can provide some specific guidance for the rest of the year. So Ron?
Thanks, Jay. On slide 22, we provide financial guidance for 2021. The updated guidance from our November call reflects the impact of the timing of our drilling and completion schedule as well as the shut-ins that were discussed earlier in the call.
Looking at 2021, our development CapEx guidance is $510 million to $550 million. And that budget anticipates the release of one of our operated rigs in May as Dan mentioned. We also anticipate spending another $7 million to $10 million on leasing activities.
Our production guidance is 1.33 to 1.425 Bcf per day. Our lease operating costs expected to average $0.21 to $0.25 per Mcfe in 2021 and our gathering and transportation costs are expected to average $0.23 to $0.27 per Mcfe. Production and ad valorem taxes expected to remain in the $0.08 to $0.10 per Mcfe range and our DD&A rate is expected to average $0.90 to $1 per Mcfe. As mentioned earlier we believe our cash G&A rate is expected to return to the more normal $0.05 to $0.07 per Mcfe range.
I'll now turn the call back over to the operator to answer questions on the call.
[Operator Instructions] Our first question comes from the line of Derrick Whitfield from Stifel. Your question please.
Thanks and good morning all and congrats on a strong quarter and positive outlook. Referencing Slide 8, you guys were fully impacted by several uncontrollable events in Q3 and Q4. And I'd imagine Q1 could similarly be impacted by the current weather. At this time do you have a sense of weather-related outages for Q1 and more broadly beyond Q1? How would you envision that shut-in metric trending based on your 2021 outlook?
Yes that's a great question Derrick. And the -- in some of the shut-ins obviously for the fourth quarter were voluntary. We didn't want to accept really low spot prices. So some of our gas that wasn't nominated that's in the -- our swing gas, we decided to shut-in in the first part of October. And so -- but I think as you go into 2021, we haven't had those type of issues. We've had very good -- really very good spot prices so far all throughout 2021. And then obviously in the last -- with all the events in Texas in the last week obviously incredible spot prices for our swing gas.
Our marketing department with the index prices kind of being set lower at the beginning of the month and the rising gas prices both in January and February that we've experienced. We actually were a little bit less -- we actually exposed ourselves more to the spot market than normal and that's going to pay off, I think handsomely and improved price realizations in the first quarter.
Especially whatever gas we've been able to sell over the last -- ever since last Thursday just some phenomenal pricing opportunities which hopefully will -- and it will probably continue through the week. Now the negative to that is, is there going to be shut-in production due to the weather?
Through Tuesday we could have said no we were at really full production all the way through Tuesday. And then starting yesterday we started to see some issues with -- where water haulers really can't come and service with the wells because of the road conditions in North Louisiana.
So we see some shut-ins now that are close to 20% of our normal production levels. We think that's only going to be in place for a few days. It really depends on when road activity can resume. And then once road activity resumes we can hopefully get back to normal production activities.
Derrick one of the good things and Dan and Patrick and really the people in the field have done a really great job. Some of the wells that we had shut-in because we were fracking some wells since the frac crews were frozen out everywhere. We were able to bring that shut-in production online. So Dan Harrison may want to comment on that. And again it's our field people that did such a phenomenal job on that. And as Roland mentioned the marketing people Alex Whitney etcetera the whole group. I think they've really delivered great results. Dan any comment?
Yes. I'll just basically add to what you said Jay our people here in office and the field have done a fantastic job. Our frac crews have been down since roughly probably Saturday morning. And we did have a substantial amount of gas that we put back on production, when the frac crews was shut-in for offset frac protection and we did get that production back on from Saturday, through Tuesday. So we actually had a lot higher -- we had a lot more gas production, from Saturday through Tuesday when the prices spiked.
We're kind of starting to see the effects of that really just starting yesterday. Like Roland mentioned, we just can't get the water haulers to service our wells and all our tanks are filling up for the water. And a little bit of downtime with the midstream treating plants, also not really freezing problems per se at the wells, but just kind of those two things, I mentioned is what's starting to get us -- really just starting yesterday. So, kind of probably through the remainder of this week, until we get kind of some above freezing temperatures, I think, we'll have is where we'll see the effects.
So like Roland said, I think, our prices will be a little higher. I don't think it will have a huge impact from shut-ins. I think, we don't give any guidance, but if anything it should lean toward the positive.
And keep in mind, Derrick. In a normal quarter we'll always have, anywhere from 3% to 5% shut-in to -- around our completion activity. So that's -- what's abnormal is when we go to 7% or 6%. And so, -- we'll have to see how the first quarter ultimately shakes out.
But, there could be more pluses and minuses from the store as far as overall profit to the company. We'll know more, I guess in a week or two to really sum-up the impact. But right now we think that we might -- overall it could be a very positive impact on the first quarter.
We'd like to get back to norm, but 2020 you have the COVID that wasn't norm. And you have all the storms that, wasn't norm. You had -- we had this weather coming in for 2021. So that's not norm. So, I guess, we should just start to live with that outside the norm.
But these numbers in 2020 even though, again is like we said, it's a whipsaw year they were really good numbers. In 2022, kind of starting out like this with weather issues, where we are with this demand and the performance of the field people. I think you'll be pleased with the results that hopefully, we can show you.
And I think this week highlights, what's unique about Comstock one, we're in the Gulf region. So, we were really able to take advantage of some of these really super-premium prices. And two, we don't have huge mid-stream commitments.
And we have a lot of flexibility in our marketing. And so we were able to move gas to some really great premium opportunities. And I think our marketing group is working overtime, during this -- spotting these opportunities that truly said showing up last Thursday and will probably continue through this week.
And -- but that's the unique thing about Comstock is the flexibility we have in marketing strength I think. And we have the strength like we showed in October, to pull that gas off the market and not have to sell it at a very low price. So I think, that's, a strength in both sides.
Well. And again, we've mentioned earlier this LNG. I mean, LNG pulled back from 11.2 bs to about 6 bs or 7 bs, because the governor the Texas Governor called, Freeport and Corpus Christi and said, "We need that gas to keep these homes warm." So even with LNG pulling back the export to Mexico pulling back two or three Bs.
I mean you still see where the challenge is of meeting this demand. So we're in the right area. We're a couple of hundred miles from this corridor, where you need to be that for these transportation costs are a lot cheaper than if you're in Appalachia. They're probably $1, $1.5 cheaper in certain areas. And we have pipelines available that if you do need more gas. We can really supply it, if we really do need it in the long run period.
Well, guys, thanks for the very comprehensive response to that question. Is my follow-up perhaps for Jay, in light of the more constructive gas backdrop that we're seeing and your success in adding acreage during the quarter? Could you comment on the current state of the A&D market?
Yeah. We think -- and we still think you're going to have consolidation. I think that, Wall Street should not allow material production growth. I mean, kind of like Devon announced today, they've got a variable dividend. And they're the first company to give a variable dividend.
I think all these companies their leverage ratio needs to be down. Their bank borrowings need to be down. We think that the new norm is of course cleaner energy. And I think that's why Jerry Jones invested his $1 billion plus into Comstock, because we do have the cleanest fossil fuel. I mean, we can clean it up more, we're going to do that. I think that bigger is better if you keep your quality. If you keep your cost down most of these deals as you know they were done with stock and that assumption of debt except maybe the Chevron deal with EQT. And I think that was a blend of stuff.
But if you're looking in the Permian, I think the challenge in the Haynesville is you've got a lot of private equity-backed companies. So you don't have really a numeral of denomination as far as value. And you do on publicly traded companies. So I think there'll still be a push. I think some of these companies will come a little more gassier, because they probably should. And I think we're kind of in that sweet spot there that that if we came off a big $2.2 billion transaction with Covey and it was Tier 1 the whole way. And like Roland said, we were one of the very few companies it's pretty thin air. We don't have any impairments. You got $1.99 gas price and you've got a really low oil price, you don't have any impairments. And then we had all these adjustments for reserves for successful operations this year.
So if you can continue to do that then I think you should see an active M&A market. But we expect it. We expect the Haynesville to get fewer in number as far as companies this year and in all other basins, but we try to -- it's your money, it's your company and we try to not just grow for the sake of grow and have to grow not to make a lateral movement to make a forward important movement. And you have to decrease your leverage when you do it.
So that's the market we're in and that's what we see for the future. We've got 18 or 19 banks that have guide us. We probably have a dozen research analysts that follow us. We're thankful for that. We added more in 2020. We've been in the bond market as Roland said two times for this last year, $500 million in June and $300 million in August. So we've got very good allies there and they tell us the truth on what we need to be doing or not.
So I think we're going to have access to the things we need if the opportunities are there particularly with the backing of the Jones family. It's smart money, in a smart business, with a smart product. So that's where we are. It's just a little bit of rambling, but you have to ramble in the world of the public as you know.
Very helpful guys. Thanks for your time.
Thanks, Derrick.
Thank you. Our next question comes from the line of Dun McIntosh from Johnson Rice. Your question please.
Good morning Jay.
Good morning.
Maybe for Dan, but on the 2021 guide you've got CapEx and activity down a little bit in production kind of modestly up despite call it five less turn in lines. I appreciate the increasing efficiency you're seeing on the drilling side. But what are some of the things that you are seeing that give you confidence in hitting that production number despite few returns? I mean, is it -- you going to be targeting some higher return areas? Or is it more driven on the shift back to higher intensity completions? Any color there would be helpful.
Yes, I'll let Dan answer that then I'll clean up if I need it. Okay. Dun, here go.
So we're really encouraged by what we've seen on the drilling side. It's been pretty sustained. We see it getting better. Actually going forward, we are going to try to get longer in our laterals, which are going to give us better returns. I'd say the activity as far as where the wells are going to be are still a pretty good spread across all of our acreage.
We mentioned in here we have gone back to the larger frac jobs. We did -- and I think it was still the right call to go and try the lower frac jobs. We're in a really low gas price of environment and we got some production history on them. They didn't look terrible. but we looked across the board and this was really kind of the East Texas far kind of North Caddo areas we maybe 0.2 Bcf per 1,000 kind of we saw short for the smaller jobs.
We really haven't -- we never really changed our job size over in the better areas of like Grand Canyon, Logansport and Elm Grove. But so I would say a little better performance from going back to the larger frac jobs getting longer and basically drilling faster getting cheaper.
Yes Dun, I think the biggest factor toward the more efficient 2021 plan when we even looked at it in the third quarter is the drilling time. That's been the -- a little bit of -- so basically wells are coming on quicker. And so it's just a more -- the capital you're spending is generating production a little bit faster because of these really good drilling times that the operations group is achieving. You might maybe give some example.
Yes, that's one reason, we try to break out. We take you along this journey with us because it's again your time and money. On 2018, 2019 and '20, we might be the only company that has gone that macro with kind of a shovelnose to shovel there to go into what we look like with greater than 8,000-foot laterals shorter than 6,000 foot and between 6,000 and 8,000. And what we've been able to do is as Dan kind of chose to me he'll snap his finger. He said we used to drill those 4,500-foot wells pretty quick. And now we drill those 10,000-foot laterals and he'll snap his fingers pretty quick and predictable.
If you look right now, we're at 12,000 13,000 foot. And quite frankly, we don't want to get people too excited, but the longer these laterals are, we can get them 13,000, 14,000, 15000 feet. These economics are really, really are favorable. And we've -- again, I don't think there's any company. You put everybody together, all 200 firms together. No company has drilled or completed more extended lateral has completed Haynesville/Bossier wells that we have. So Dan, may give a little peek -- give a few examples.
Give a few examples here Dan of how much the drilling time has changed on the long laterals?
Well I mean like on average. So we -- a 10,000 lateral before let's just say you spud to rig release you were at 28 to 30 days. I mean, if you get those down to 22, 23 days, you apply that across five rigs, across an entire year. You're turning a lot more wells to sales. That's a lot more frac jobs. That's more cement jobs. That's more strings of casing that you're buying. So your budget goes up, right? I mean, with the same number of rigs, you're actually spending a lot more money. So, it allows us to dial it back, drop a rig. Basically get the same results with less rigs.
Right? The production comes on earlier and you use less equipment to get the same type of results. So, I think that's I think that's a little bit of what you see in the outlook for 2021 versus really three months ago.
Well if you go over we used to drill those 4,500-foot laterals we drilled 500 feet a day. If you look at the wells we drilled within the last three, four months, we've gone from anywhere from 6,000 feet a day which is anomaly to 2,000 or 3,000 feet a day which is kind of the norm right now. So that is the difference. And we use a couple of thousand feet a day. We'll get a little more than that on some of these, but we'll have a hiccup or two. So that is really the answer. And we're comfortable enough to start kind of advertising that on the low side. So, we -- hopefully we can meet this.
All right. Great. Thank you for all the color. And then just for a quick follow-up. One of your bigger competitors recently coming out of bankruptcy in the basin. Just if you could just remind us kind of how much exposure you all have to them from a non-op perspective? And I'd have to imagine you've been in conversations with those guys? And how good of a feel do you have for kind of what they have planned for this year? And what that could mean for you all?
Yes. Yes, they spun out the 50,000 acres to the South and Williams owns that and Williams is just trying to do something with that as that's public as part of the bankruptcy. And then 85% of Chesapeake, their budgets in gas some of it is in the Marcellus some of it's in Haynesville. I think they're going to keep two or three rigs busy. We know them really well. We're glad that they came out as aggressive as they did and as clean as they did, getting rid of that $7 billion or $8 billion of debt and it'll make the sector look good now. But I don't think they're going to drill too many wells to upset the balance of supply. I think their board will take care of them.
No Dun and to your question was -- we don't have a lot of exposure to Chesapeake operated projects and we really -- and actually they're -- the amount of rigs they're running, what they're talking to their investors about is not very different than what they we're were doing while they were bankrupt. So their activity level is not that materially different in the Haynesville. But we don't have a lot of exposure to their operated projects.
In fact the last wells that we had exposure to, we bought that acreage and renegotiated the firm and drill several wells.
Yes, we operated –
So it's all positive. But we don't have – our exposure and our numbers to them is minuscule.
Okay. Thanks for that.
Thank you. Our next question comes from the line of Neal Dingmann from Truist Securities. Your question, please.
Good morning. Jay, my question for you or Dan. I'm looking at that slide and Derrick kind of touched on this a little bit. On slide 15 just shows the massive footprint. Could you give an idea just on cadence – I know you were talking about, I guess, what I want to try to be clear Dan was talking about maybe some of the larger jobs. I'm just trying to get a sense of with the five rigs running this year maybe geographically where and kind of what size or what type of wells you're going after?
Well, I think that overall a large percent of the wells are going to be the long laterals probably 80% or so. 75% to 80% of our budget will be just like it has been in the last couple of years will be for laterals over 8,000 feet. And I think the overall averages are probably going to go up, because of these extra-long lateral wells that we're doing 12,000, 13,000 feet. But we still plan to drill wells across our footprint and not any – in that concentrate in one part of our large footprint in the Haynesville.
Yeah.
And, Neal, something I would add is you got to be careful to really just focus on one area because you got to – we have to look at our midstream capacities and where we can get rid of the gas also. So sometimes you can't bring on a real high peak volume of gas in one specific area, because the midstream can't handle that all at one time.
But we like to try to minimize that shut-in time for offset fracs. So if we always drill wells at our very best area, we'd never be able to produce our best wells. And so part of the whole drilling plan is also looking at how do we optimize overall production from the different areas, looking at midstream, looking at shut-ins. So it's all – when you look – you try to blend all these things together to create the best program for the dollars we want to spend. And I think that's kind of what we have in-store for 2021.
Yeah. And I think that goes back to the quality inventory. we tiered all Tier 1, 2, 3, 4, 5. I mean, it just depends upon where the price is what the midstream looks like, et cetera, et cetera the cost the depth. But we have the last three, four years, I mean, we drilled all parts of our inventory. And you can see what the numbers look like. It is not just leaning on Tier 1, Tier 1, Tier 1, Tier 1 plus, the numbers we give you it's a pure blend of our total footprint from North, South, East, West. That's very important. And our PDP component shows that.
Now in the last several years, we've had some joint ventures where we were earning acreage based on drilling and we also did a special kind of program with our majority stockholder. These were in Caddo Parish area. And some of that was – some of our more northern acreage. At one time, it was very extensional to the play. But all – most of that's all been fully developed now. And so we were drilling there to finish that up now we typically didn't have high working interest in those projects. But all those projects have been finished.
And so I think what you look ahead you see us more just having free rein to go anywhere in our footprint and everything we're doing is probably a fairly high working interest. So that's a little bit of a change overall from – maybe if you just look at our historical deal, I think, it'll be positive from the standpoint higher ownership overall and each well we drill, because we finished those joint venture opportunities.
That will drop our rig count like we said.
Right. And that's part of the reason, why I can have a little bit lower rig count. Because we're not drilling low interest wells with one of those rigs like we might have been in the past to kind of finish up our joint ventures for our partners.
We think, we've got a good hedge book starting in for 2021 that's 65%. And like Roland said, we'll be in the 55% to 70% range in hedges other than swaps for collars and 2022 is our goal.
Great detail Jay and Roland and Dan, appreciate that. One follow-up, I like how you guys are being, I guess, my question is with the five rigs plus and you definitely show that great returns that you have. Could – Jay you or Roland maybe talk about what I appreciate is versus some folks that are trying to go after free cash flow that just immediately try to drop all rigs and generate the near-term free cash flow which you know they can. I think you'll seem to have much more sustainable type plan. I'm just wondering as you mapped out the plan for this year with five rigs. Could you discuss that a little bit how you arrived at that?
Sure. What we did in 2020 again, it was a strange year. I mean, we came off a huge acquisition in 2019. 2020 was a very disruptive year for everybody. When we go two, 2.5 months without a frac crew working and we dropped our rig count from 7, 6, 5, 4. Even with that we ended up with a really good year. I think 2021 is a settling year. Some of the JVs that we had they're gone. The longer laterals we've become more and more and more comfortable with that. That's why we break that out on page 18, 19, 20.
I think the marketing group has done a good job. So you're going to see some increased production in 2021 only because it's kind of a catch-up from what we did at the latter part of '20. And then I think when you roll into '22 you'll see to that 3% to 5% growth. But since our costs are low that's why we're able to have this $200-plus million of free cash flow. It's -- like Roland said, we have more undedicated gas in Haynesville than any other company. We market about two Bs a day we sell 1.2, 1.3 plus 1.4 on our own. So I think all of those things combined, give us this 2021 I mean really good solid feel where you see a lot of these companies they've -- if you keep your budget flat usually your production goes down. If you increase it a little bit your production may stay flat.
The one great thing we have we can keep this $510 million plus with these DUCs that we have kind of rolling over we can have really good production growth in 2021. We'll have great free cash flow in 2021 and we'll carry over that in 2022. And it's just you can see it works but it's an anomaly in the whole world of energy.
Yes. I think like Jay said that -- and we did -- it was kind of a -- we were going from a high-growth company in 2019 with -- after the Covey Park acquisition. You had the low prices of $20. We reacted pulled the rigs way back. And then searching for that level of sustainability like you asked I think that did take us a little time to think through and I think really adapt to the new drilling times.
And so I think we looked ahead. Looking ahead, we do kind of look at a sustainable kind of free cash flow number which we can continue to grow on, grow from. But that five rigs kind of cemented into kind of providing that kind of longer-term growth. So we catch up here in the first quarter with catching up the DUCs from last year. And then we decided, hey these five rigs is a sustainable program that can go into '22 and go into the future create kind of the what we're really looking for which is we do want to focus on free cash flow and then have modest growth of production, but we wanted to do it from a position of strength. So we had to get back to our full strength after really playing defense in '20.
So I think that we're really pleased with where the outlook is now. And we certainly don't -- even with higher prices we just look at that as an opportunity to get caught up really quick on the balance sheet. That's the major goal of the company. And we wanted to put the production level at a level that's sustainable, but also at a proper level for the leverage we have. And we've accomplished that in the first quarter and then we can kind of sustain and then we're really focused on free cash flow in the future. And I think we have all the tools to do it. So we are in perfect strength.
So one thing that -- in 2021, we -- I would say that we've kind of digested Covey in 2020 even with COVID. So I think our model is a lot better. I think David Terry has done a really good job working with Ron, working with Dan and Patrick McGough and others to get our model. What does our model look like? What are the drilling costs? Where are all the sticks? Where is our almost 2000 sticks on the map? Which ones will we drill? You give it to the marketing group and say can we sell our product there?
Our model is so much better now than it was even in third quarter, that's why we're so positive in our tone, in our numbers about how far we've taken this company in a short time. But the model is so important. And again, I really give Ron the credit on that, because he's accountable for really the model and the numbers to the analysts.
Great, great details. Thank you all.
Thank you. Our next question comes from the line of Leo Mariani from KeyBanc. Your question, please.
Hey. Just one quick question for me and perhaps, this is for Ron potentially, just a question on the guidance. What can you tell us about kind of the cadence for CapEx in production and just thinking on kind of the quarterly basis here in 2021?
Ron, you got a shut-out.
Yeah. Leo, we only really provide the annual guidance for -- that's the typical guidance. I would tell you that with the carryover for some of those DUCs that were mentioned earlier in the call. The first quarter is going to be the highest spending level. The fourth quarter is going to be the lowest, and then the second and third quarters will be somewhat in between. And then, in terms of the cadence on the production side, we'll see pretty steady growth over the first three quarters, and then that flattening out a little bit in the fourth quarter given the current status or schedule of completion cadence in the fourth quarter.
Okay. That’s great color. Very helpful thought for me. Thanks.
Thank you.
Okay, Leo.
Thank you. Our next question comes from the line of Umang Choudhary from Goldman Sachs. Your question please.
Hi. Good morning and thank you for squeezing me in. I have a quick question. Gas futures have improved. I wanted to get your thoughts on what you're seeing from non-operated partners with respect to activity levels? And also, I guess I wonder what price point would you actually consider adding activity, say, if the gas prices keep improving here?
Yeah, good question. We're probably not a good one to ask about non-operating partners, because that's just such a small part of the company. We just don't have a lot of exposure. We have a little bit to some of the private companies in the Haynesville. A little bit to Chesapeake, but we see their activity level being very -- fairly similar to where they've been.
As far as -- we really aren't looking to use the extra revenues that probably come in from these improved prices, because we like the growth profile we have in place now. And so we would just use that to accelerate our delevering and that -- because that's our major goal, so.
Again 91% of what we have we operate. So, we don't operate any of the Bakken. That would be the biggest part that we don't operate.
Right. We don't really -- and the Bakken has become a very small part of the company, 2% of the company. So, it's not that significant to us. But overall, yeah, we will use high -- hopefully the higher prices to just to achieve our goal of getting under two times levered faster, because that's really the major goal the company has. Everything else is how do you get there.
And we think that we've got the right production profile that fits the company well, and so now it's really like the leverage is not where we want it to be. In the next two years, our goal is to really come back and be able to tell you at the end of two years that we have the balance sheet that we want and the cost of capital now reflects that and we will consider that a big success.
Well, the like analyst say, we're low-cost producer high margins. We've got impeccable inventory. The weakness that we have is our cost of capital. So we did incur debt, although we added equity and delevered with the Covey. We added expensive bonds. That's mainly the high cost of capital. So we've got to deal with that in the future. But, I think we can do that internally in the next year or so.
That makes sense. Thank you so much for the color.
Thank you. Good questions.
Thank you. Our next question comes from the line of Noel Parks, Tuohy Brothers. Your question please.
Hey, good morning.
Hey, Noel, morning.
Sorry if you touched on this already, but the amount you spent for new acreage leasing in fourth quarter, I think it was about $6.5 million. Was that just bolt-on acreage you've had your eye on for a while?
Yeah. We're opportunistic all the time. If we can add Haynesville acres, that we think will either lengthen our laterals or give us good drilling locations in the future. I mean, we're always opportunistic on that, we always have been.
Yeah. Given that -- and we think there's not a lot of competition for that type. And so we've really been working that hard. And have a lot of looking across the whole landscape of the prospective Haynesville. And trying to find any kind of open leases and go after them. So, that's something we've allocated some dollars to do in 2021 also.
Great. And you talked a good bit about the gas environment. And already have an eye to hedging in 2022. And as I just looked at the futures curve, I was wondering, do you think 2022 is still relatively low considering the demand profile? I'm kind of wondering if we have another leg up you think in the 2022...
We think [Indiscernible]
Yeah. We think definitely. And we think the 2022 -- I mean, -- and it's not -- it's a problem that we've had for a longtime. The longer-term curve just reflects a lot of the illiquidity of the natural gas futures contract. And so people talk about oh why don't you hedge out five years whether just -- if you're a large producer it's hard to do.
You take a -- and so that's why our 12 months to 18 months kind of cycle is our hedging. And we do think 2022 is not priced right in our opinion. But we're mainly going to be able to hedge though pretty attractively using collars more in 2022.
So we can have some of the exposure to the upside that probably shows up. I mean, the gas market in our opinion is going to be pretty tight this summer. And I think that people have been non-believers in gas and really tortured gas with the warm winter. But I think they could end up with a pretty big very tight market. That's what everybody is telling us for this summer.
I mean, we think 2022 goes many legs as the center peak going up. We definitely think it's positive, not negative.
Great. And one thing I noticed, in the reserves. I noticed, you had 300Bs, almost 350 Bs of positive performance revisions. Can you just talk about those?
Yeah. We're pretty proud of that. And I think in a year when you're using a low price. Typically you're fighting that, but these wells have such a low-cost structure that we didn't really suffer from having a bunch of non-economic reserves. We always lose a little bit of reserves from using a very low price in the tail.
But overall, I think, we've been very conservative in our reserve bookings for undeveloped wells. And I think as they -- they're booked fairly conservatively. And then as they're drilled, we obviously have additions there, at a higher number than they were booked at, plus just -- we actually had overall positive revisions on our PDP and all our reserves from the performance of the wells.
So I think it's -- it points to the good job operations do, but it's also I think that it's a testimony to -- we're very conservative in preparing those numbers. And so they're conservatively booked. So when they actually become real wells, they typically have an upside to them once they are really drilled.
And I think that -- look back shortly. And we haven't had negative performance revisions in long, long time. And I think that's a testimony to the quality of the properties in the conservative bookings that they were booked at.
You know what that's a great question too, because most people don't see that. Don't -- they never ask that question. It's a great question. They have 367 Bcfe of performance revisions, added in a terrible year for pricing. That's again, that's a good marker they we're solid on that.
Yeah. And just to give you some perspective. So, sort of, what vintage of bookings worthy, that you're seeing the performance revisions? Is it sort of stuff from four, five years ago, where the tail decline isn't as deep as you thought? Or is it just outperformance of more recent wells?
Well, I think it's the overall Haynesville well. It's also the fact that, it's hard to see in the numbers. But generally what's happened to our inventory is that we've turned short laterals into long laterals and they've become more economic. And there's been a lot of remapping of the inventory. And we had -- I think we had just closed Covey Park so there was a little bit of integration to kind of really get all that done. And probably didn't have that optimized at the end of 2019 in our reserves. We probably had a -- and I think as we were able to work through and redraw the laterals and et cetera and the performance of the wells overall and the lower development costs that they now have compared to what we expected in 2019.
A lot of positive factors kind of contributed to that. But including just the actual wells, their actual performance was better than what they were in the reserve report for. So I think all those together as another good year of positive revisions which we had last year also.
Terrific. Thanks a lot.
Thank you.
Thank you. Our next question comes from the line of Kashy Harrison from Simmons Energy. Your question please.
Good morning, all. Thanks for taking my question. I'll keep it simple. Just one quick one for me. Can you discuss what proportion of gas in a quarter would typically be sold on midweek versus the spot market? Thank you.
Yes. Good question. I mean our -- typically we target to have just about 75% to 80% and sell the index basis because that's kind of how our -- the index prices match up well with our hedging program right? The spot prices might not because of the -- and so -- but we can't go to -- we don't want to go to a much higher percentage because we have a lot of new wells coming on and there's production issues can come and go. So we don't want to ever be caught having to buy gas fairly something we can't deliver on. That's our basic rule.
Now I think there's -- there are sometimes when we just say they just said that -- I think we took -- we probably went lighter on selling into the index market for the first quarter so far. And we were more -- I think we were more at what was our exact number Dan, do you have it there? I think we're more 35% in the spot market for...
Yes. I think that's right.
For right now. Yes 35% to 40% actually for the month of February.
Yes.
And that was a little bit lighter than the month of January. So we're a little bit more in the spot market than normal. A lot of it though, we do have a big ramp-up in production going on in the first quarter. So that's part of that. You want to be conservative as you're bringing on a lot of wells because you don't have the exact timing. And -- but I think that's paid off pretty well in both January and February because prices have been moving up.
And then obviously this week is like hitting the jackpot as some of these incredible prices. I mean frankly, we were able to sell -- get super-premium prices for a material amount of production anywhere from $15 an Mcf to maybe some even at $179 an Mcf. So those are the spot prices that are out there.
But to answer your question, I mean 70% to 80% that's kind of the norm for...
That's the norm that's where we like to be. Yes. The 40% that we might be in February is a little unusual.
Yes.
All right. That's it for me. Thank you. And looking forward to seeing those realizations, when your Q1 earnings.
Yes, that will be what we're interested to see how it all shakes out in the end too.
Good question.
Thank you. Our next question comes from the line of Phillips Johnston from Capital One. Your question please.
Hey, guys. Thanks. Just one for me as well. It's really just a follow-up to Roland's comments on the leverage ratio target. It looks like you guys have probably hit that sub 2 times target probably by mid '22 or so if the strip holds. Jay you mentioned, Devon paying variable dividends. I'm wondering if you could address the Board's preferred method of returning cash to shareholders once you sort of achieve that leverage ratio goal?
Well -- as you well know, I mean at the end of probably 2014, we were a dividend issuing company. We think we issued $0.125 per quarter. So we did that. And of course, I mean the wheels fell off the sector in the first quarter of 2015. So our goal -- every company should have a goal of being in a position to have giving a dividend period I don't. I don't think we have enough shares to be buying shares back. So we don't see doing that at all. We need to get more shares in float. I think, we've got great inventory. We need to get the stock price performing and then we need to be -- US can heck on the dividends is not high enough question. So that's our goal. We want to be in a position to be able to give a dividend period.
Well addressing the leverage first because you want to have the right balance sheet.
Yes. We have to do that. Hopefully, we can do that in 2021 and 2022.
Yes. No I agree 100%. Is there anything about variable dividends that you see as maybe being a drawback?
No. I think once you've got the size of a company that you need and you've got the inventory. I mean Devon just did a big acquisition a consolidation. I mean, they've got the bulk they've got the market cap. They've got low-cost of capital. They've got inventory. I mean we don't have any -- but right now, we don't have any issues as far as where our acreage is located to get drilling permits that are material at all. So our acreage is well-positioned in good areas. So they're not kind of politically charged issues around them. I think that's good.
But no, I think, Pioneer came out with a variable concept and Devon issued one. I think that's the new business plan. I mean you've got a -- that goes back to the question of M&A. Do you need M&A? I think you do you have to have bigger have to be more predictable. You can't rely upon capital from Wall Street to feed a company that's not making any money. You have to have free cash flow. I mean all those things I believe we're going to give you and are giving you and kind of at the end of that funnel is you need to have a company that can give a dividend period, that's just another sign that you're healthy.
And we'll be able to -- since we're going to work on our balance sheet like you said for this year next year we'll be able to see how the variable versus fixed dividend, kind of, work with these other -- with our other peers. And so we'll be able to kind of look to see at the market which method they like better. And so we'll study that to make a real decision on the structure. First job, number one is getting the balance sheet to where everybody is very comfortable saying yes you should be paying a dividend. And so we're focused on job one.
Yes. Absolutely. We've always said that. We've got to get our cost capital lower. We've got to get our leverage down. You'd love to be in the onetime. I mean, we're at 3.8. We want to be in the 2.5 -- low 2s, by the end of 2021 and then lower in 2022. But then I think you have to have something in your scope around the corner and that is you want to be able to have the flexibility to have what kind of hedges we need or don't need and the leverage needs to be down. Leverage will get you in trouble time is on your side. We've got long-term bonds. That's favorable. Our leverage is too high. Our cost of capital is too high.
Agree with all those comments. Thanks, guys.
Thank you.
Yes.
Thank you. This does conclude the question-and-answer session of today's program. I'd like to hand the program back to Jay Allison for any further remarks.
All right, Jonathan. I just have one closing remark and it's kind of a housecleaning item. We received a notice from the New York Stock Exchange this week thanking us for 25 years of listing partnership with them. They attached a customized listed emblem highlighting Comstocks milestone. So it's kind of a thin air to be an NYSE company for 25 years. I mean even for some of the most recognized largest companies in the world, but we are there.
And if you have time to go to the Comstock website to see the emblem please do or if you want to turn to page 22 in our corporate presentation day you can see it. But again, I want to thank you for trusting us with your time and with your money. And we want to close every day as a stronger company if we can. So great questions, great support. Stay warm, everybody.
Thank you, ladies and gentlemen for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.