Earnings Call: Q1 2020

May 7, 2020

Ladies and gentlemen, thank you for standing by, and welcome to the Q1 2020 Comstock Resources Incorporated Earnings Conference Call. At this time, all participants lines are in a listen only mode. After the speakers' presentation, there will be a question and answer Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and Chief Executive Officer. Please go ahead. Tina, thank you and good morning everyone. We know it's a crowded morning. The docket is crowded, lots of earnings reports came out last night and this is a prime time slot. So those of you that are participating right now, thank you. I have a few comments before we start the formal presentation. The last 60 days has stress test every business in the world, especially the oil and gas business. We as an industry are managing the ripple effect of the initial increased oil supply from the Saudi Arabia, Russian oil feud, which has been down back as of this month, coupled with the coronavirus pandemic that has reduced the demand for oil by 25% to 30%. Fortunately, however, Comstock is 98% natural gas, has an industry leading low cost structure in the Haynesville, has industry leading high margins, has hedged almost half the production high margins, has hedged almost half the production expected for the next 12 months and has meaningful free cash flow. Since we are 98% natural gas, we have already become a beneficiary of the corrected oil market as we see associated gas being shut in and a collapse in the rig count occurring. Roland Burns, our CFO, will report our strong Q1 results. And Dan Harrison, our COO, will tell you why our costs are down and should continue to be lower in the months ahead. Our numbers are solid because of our consistent stellar well results and the location of our natural gas fields being in proximity to the Gulf Coast market. Here is our report from the 2 70 employees at Comstock that made this quarter successful even in a very difficult energy environment. Welcome to the Comstock Resources Q1 2020 financial and operating results conference call. Today, we'll review our Q1 2020 earnings and drilling results. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly result presentation. There you'll find a presentation entitled 1st Quarter 2020 Results. I have Jay Allison, 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 and Investor Relations. Please refer to Slide 2 in our presentation to 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 could be no assurance that such expectations will prove to be correct. Now if you'll turn over to Slide 3. On Slide 3, we cover some of the highlights for the Q1. Most importantly, our natural gas operations in North Louisiana and East Texas have not been adversely impacted by the COVID-nineteen virus pandemic that has disrupted all of our lives. We've been able to maintain our normal operating activity and adjusted will impact our oil will impact our oil properties in the Bakken and Eagle Ford, but have inversely had a positive impact on natural gas prices. We feel that the reduced activity in both gas and oil directed drilling will create a healthy balance between supply and demand for natural gas. The one statement that has remained very consistent is that our HaynesvilleBossier Shale drilling program continues to deliver strong results. Comstock and Covey Park had drilled and completed a combined 2 37 operated wells since 2015, which had an average IP rate of 23,000,000 cubic day equivalent per day. We have drilled more than any other operator in the play during this period. Our drilling activity drove the 27% year over year growth from our HaynesvilleBossier properties since the Q1 of last year on a combined basis. We have also been driving down our well cost in the same period. The 1st quarter well cost per lateral foot are 15% lower than what we averaged in the Q1 of 2019. Recent well costs have improved even further and we expect our well costs to average $1100 per completed lateral foot in 2020. The strong natural gas production growth this quarter was offset by weak natural gas prices in the Q1. For the quarter, we reported oil and gas sales of $271,000,000 which is a 105% increase over Q1 2019. We had adjusted EBITDAX of $202,000,000 up 108% over Q1 2019. We also reported operating cash flow of $156,000,000 up 120 percent over Q1 2019 or $24,000,000 or $0.12 per share. Now I'll have Roland cover the financial results in more detail. Roland? Thanks, Jay. On Slide 4, we show the combined Comstock and Covey Park production from the Haynesville Bossier Shale since 2016. In the Q1 of this year, production from our Haynesville and Bossier wells is up 27% to almost 1,300,000,000 cubic feet per day as compared to the about 1,000,000,000 cubic feet per day. Comstock and Covey Park combined produced in the Q1 of 2019. Production grew only slightly from the Q4 of last year due to the fact that our first quarter completions came online fairly late in the quarter and we had a higher than normal shut in rate this quarter as we'll go over in a minute. We did put 11.5 net wells on production during the quarter. In the Q2, we see the rate of our Haynesville, Bossier properties really staying relatively flat, with only about 4.5 net wells coming on production during the Q2. Our completion activity is expected to pick back up in the Q3 and we'll see some growth in the Q3 and Q4 of this year. Slide 5 recaps the production we had shut in for the quarter and this was production was shut in principally for offset frac activity, either by us or by offset operators. Our 1st quarter shut in volumes increased to 5% as compared to only 2% in the Q4 of last year. Offset operating activity as well as our own completion activity caused us to shut in production in some of our best producing areas. Given the lower number of completions planned during the Q2 and our planned activity level going forward this year, we do expect the shut in volumes to return to the 2% to 3 percent level over the rest of the year. On Slide 6, we summarize our financial results for the Q1 of 2020. Our production for the Q1 totaled 126 Bcfe, including 450 4,000 barrels of oil. This is 230% higher than production in the Q1 of 2019. Our oil and gas sales including our realized hedging gains were $271,000,000 105 percent higher than the same quarter in 2019. Oil prices in the Q1 averaged $46.31 and our realized gas price, including our hedging gains, averaged $2.04 per Mcfe. Our natural gas price realization was down 29% in the first quarter, which offset some of the substantial production growth we had. Adjusted EBITDAX came in at $202,000,000 that's 108% increase over 2019. Operating cash flow was $156,000,000 120% increase over 2019. For the quarter, we reported net income of $30,000,000 or $0.15 per fully diluted share, But adjusted net income, which will exclude unusual items, the largest being the unrealized gain on our derivatives, was $23,600,000 or $0.12 per diluted share. Slide 7 summarizes our current hedges that we have in place for our oil and gas production. For this year, we have 619,000,000,000 cubic feet per day of our gas and 3,450 barrels of our oil hedged. Since we reported earnings last, we've added 35,000,000 cubic feet per day of gas swaps, about 50,000,000 per day of gas collars for the Q4 of this year. The weighted average floor protection price of our 2020 hedges is $2.64 per Mcf. With the recent improvement in future gas prices, we've been actively adding to our 2021 hedge position. Since we last reported, we've added almost $270,000,000 per day of natural gas swaps and $150,000,000 per day of natural gas collars for 2021. So now we have about 540,000,000 dollars of our 2021 gas production hedged and the average floor protection of our hedges is $2.52 per Mcf. We also recently added $30,000,000 per day of swaps covering our 20 22 production at a price of $2.53 per Mcf. And I'll remind you, our policy is to continue to target hedging 50% to 60% of our expected production on a rolling 12 month basis. On Slide 8, we detail our operating cost per Mcfe, which kind of demonstrates our very low cost structure. Our operating cost per Mcfe fell to $0.50 in the Q1 as compared to the 4th quarter rate of $0.55 and substantially lower than the Q1 of 2019 where our operating costs were $0.74 Our gathering costs were $0.23 Production taxes averaged $0.04 and just the field level operating costs were $0.23 for the quarter. On Slide 9, we detail our corporate overhead per Mcfe. Our cash G and A costs per Mcfe were $0.06 in the first quarter as compared to the Q4 at $0.04 And you say the Q1 has the highest amount of just overall corporate G and A due to the extra professional cost that we usually incur in connection with our year end close. On Slide 10, we detailed our depreciation, depletion and amortization per Mcfe produced. So our DD and A averaged $0.88 in the Q1, very comparable to the $0.89 we had in the 4th quarter. And it's a nice improvement over the $0.99 rate we had in the Q1 of 2019. On Slide 11, we recap our Q1 spending on our drilling and development activity and then what we expect to spend for all of 2020. So in the Q1, we spent $130,000,000 on development activities, $104,000,000 was related to our Haynesville Shale operated operations. We drilled 13 or 19.6 net operated horizontal Haynesville wells in the quarter, and we completed 13 or 9.3 net wells that were drilled in 2019. We spent another $26,000,000 on non operated or other activity in the quarter. We did generate operating cash flow of $156,000,000 in the quarter resulting in free cash flow of $16,000,000,000 in the quarter after we paid the $9,600,000 dividend on our preferred shares. We dropped our activity level to 6 operated rigs in January and then further reduced our rig count to 5 operated rigs in March. Last month, we dropped another rig to reduce our current operated rigs down to 4 rigs, although we do anticipate picking a rig back up later this year. We continue to make very responsive to the changing natural gas prices and remain very focused on generating free cash flow in 2020. We expect to spend in total $412,000,000 in 2020 to drill 47 or 36.5 net operated Haynesville wells. And then we expect to be in various stages of drilling at an additional 18 or 12.5 net wells at the end of this year. At this lower rig count and taking into account the current natural gas prices, we do still expect to generate significant free cash flow this year of approximately $150,000,000 to $200,000,000 despite the lower natural gas prices we've experienced so far this year. Slide 12 shows our balance sheet at the end of the Q1 of 2020. We recently completed the spring redetermination with our 18 member bank group, with bank price that's down 24% for gas and then down almost 52% for oil for the spring redetermination season, our borrowing base was reduced down to $1,400,000,000 We currently have $1,250,000,000 drawn on our revolving credit facility, but expect to continue to pay that down with the free cash flow that we're generating during the rest of this year. With the quarter ending cash position of $16,000,000 our current liquidity stands at $166,000,000 We also have $1,475,000,000 of senior notes outstanding, including the 625,000,000 dollars of our 7.5 percent senior notes, which are due in 2025,000,000 and $850,000,000 for our 9.75% senior notes due in 2026. With no debt maturities until 2024 and our current leverage ratio comfortably below our leverage ratio covenant of 4 times, we are very well positioned to weather the current low oil and gas price environment. As a side note, want to point out that our universal shelf registration statement that we filed 3 years ago expires next week. So we plan to file a replacement shelf tomorrow as we always want to have that available to us. Now I'll turn it over to Dan to cover the Q1 drilling results in more detail. Thank you, Roland. If you look on Slide 13, this will show the outline of the acreage position. As it stands now, we currently stand at 307,000 net acres. We currently have 19 77 net locations identified on the acreage and 95% of this acreage is currently held by production. This translates into minimal drilling commitments and it allows us the maximum flexibility with our drilling schedule for any changes in future market conditions. We also control the majority of the acreage with a 91% operated position and an average working interest of 76%. We've now drilled and completed 2 37 wells in the play with an average IP of 23,000,000 cubic feet per day. If you look at Slide 14, this shows a breakdown of our HaynesvilleBossier drilling inventory at the end of the Q1. Our total gross operated inventory now stands at 2,383 locations. Our average net interest is 76% equating to 1803 net operated locations. On the non operated side, we have an additional 1451 gross non operated locations with an average 12% net interest, which adds another 174 net locations. In our gross operated inventory mix, we currently have 580 short laterals, 9 37 medium laterals and 866 long laterals. 60% of the gross operated locations are in the Haynesville and the remaining 40% are in the Bossier. This inventory provides the company with well over 30 years of drilling locations based on our forecasted 20 20 activity level. On slide 15 is a summary of the 20 new wells we've completed and turned to sales since the last call and also shows an outline of where these latest wells are located across the acreage. As you can see, the majority of the new wells were completed in Stateline and Elm Grove areas. The initial production rates ranged from 15,000,000 to 32,000,000 cubic feet per day with an average IP of 24 1,000,000 cubic feet per day. The wells were drilled at varying lengths from 4,574 feet up to 9,885 feet with an average lateral of 8,758 feet. The wells were completed with sand loadings ranging from 2,200 pounds per foot to 3,500 pounds per foot with the majority of the wells completed with £2,800 per foot. Currently, we do not have any ongoing completion activity or frac crews working. We will be bringing back multiple crews at the beginning of Q3 to resume our completion activity. Our current DUC count stands at 13 wells and we anticipate having a total of 20 DUCs at the beginning of the Q3 when our completion activity resumes. On slide 16, this provides a snapshot of our all in D and C cost and trends since early 2017. These results track our wells which have lateral lengths greater than 6,000 feet. The D and C costs have been steadily trending down since early 2018 ending with the first quarter being the lowest quarterly D and C cost we have achieved to date in the play. Our D and C cost in the Q1 averaged $11.21 a foot. This is a reduction of $199 a foot or 15% from our Q1 of 2019 cost of $13.20 a foot. Our completion cost or more specifically our frac cost continues to be the main driver here. During the first quarter, we began testing a smaller modified frac design on several infill and co developed locations that we believe will yield better returns and economics while also preserving capital. We plan to continue Q3 and we will continue to monitor the performance from these wells. Our goal is to reduce our D and C cost even further down to $1,000 a foot. We firmly believe we can achieve this goal and we've actually made good progress toward that end with the wells that we have already completed to date in the Q2. Our goal is simple and that is to deliver the highest return and create the most value we can on the capital deployed. That summarizes up the operations. I'll now turn it back over to Jay for some final comments. All right. Again, thank you for the report. I would direct everybody to Slide 17, where we summarize our outlook for the year. This year, we are primarily focused on free cash flow generation and managing the company through the current low oil and natural gas price environment. While current natural gas prices remain relatively low, the outlook for natural gas has improved substantially for late 2020 2021, driven by our expectations for significant declines in natural gas supply in 2020 2021 due to a continued reduction in natural gas directed drilling and completion activity and less associated gas production from related activities in oil basins resulting from the collapse of oil prices. Our Haynesville drilling program generates economic returns even at today's low natural gas prices, which Roland and Dan has just showed you. We have cut back the number of wells we're drilling in order to generate free cash flow that we will use to pay down our debt and strengthen our balance sheet. That's a primary focus. The strength we have is our industry leading cost structure and industry leading well economics. We still expect 6% to 8% pro form a production growth in 2020 even with the reduced activity. We have prioritized free cash flow goals in 2020 over production growth, but have maintained adequate investment to keep our production flat on a longer term basis. We've hedged almost half of our production for the next 12 months and have adequate liquidity of $166,000,000 I'll now have Ron Mills, our VP of Finance, provide some specific guidance for the rest of the year. Ron? Thank you, Jay. On Slide 18, we provide financial guidance for the rest of the year for analysts and investors who model the company. I'd point out the guidance is unchanged from what we provided when we reported the 4th quarter earnings in late February. Our total production guidance is expected to average 1.25 Bcfe to 1.45 Bcfe per day, of which 97% to 99% is expected to be natural gas. In that number, we have now factored in a 40% shut in factor for our oil production over the remainder of the year due to potential shut ins. Though I would point out that the impact to date has not been that high. We just wanted to make sure we prepared for potential shut ins as oil producers are announcing significant shut ins. On the cost side, our lease operating costs are expected to average $0.23 to $0.27 per Mcfe in 2020. Our gathering and transportation costs are also expected to average $0.23 to $0.27 per Mcfe in 2020. Production taxes are expected to remain in the $0.06 to $0.08 per Mcfe range and DD and A is expected to remain in the $0.85 to $0.95 per Mcfe range. Cash G and A for the year is expected to average $0.05 to $0.07 per Mcfe. For the rest of the call, we'll take questions from the analysts who follow the company. And our first question comes from Don MacIntosh with Johnson Rice. Please go ahead. Good morning, Jay and Roland and Ron. And congrats on another strong quarter. Nice EBITDA beat versus us in consensus. My question is on activity kind of over the remainder of the year. 1Q, you're at 13 completions and you're kind of you're pointing to 35 for the year. Could you talk about the cadence over the remainder? I'd imagine that maybe it's more back half weighted as you look to bring on volumes into what you all clearly think is going to be a stronger tape at the end of the year and heading into 2021? Yes, Roland will address that, but I want you to know we've got total flexibility on that too, okay? With our decisions, we'll be determined by where the commodity prices are, where the sector is. So Roland? Sure. And I think like we pointed out earlier, the Q2, we only look to be bringing about 4.4 net wells to sales and those are already pretty much done now. So that mostly happened in April. As Dan pointed out, we're not we're giving the frac crews a little break here. And so we'll but we do expect to return to completing wells in the Q3. And so the 3rd Q4, we expect to see the rest of that, those the wells completed in those two quarters that we had planned for the year. Yes, but we do have the ability to decide to delay that if we want to in the 3rd quarter. So we're kind of look at see what's going on. And this plan was really put together really back when we reported the Q4 because we knew the summer was going to be a weaker part of gas prices and we wanted to have the free cash flow for the year kind of generated earlier in the year not toward the end of the year and have more production come in online toward the end of the year, going into the better market that we're seeing for the very end of 2020 2021. So we haven't made any major adjustments to the program because we already were geared up for low prices and actually prices are a little stronger than when we set the budgets, unlike a lot of the other operators on the oil side that were catching up with massive changes to the budget. But so our plan was really almost designed perfectly for the environment and everything is going very smoothly as anticipated. Hopefully, you can see we've demonstrated in the past, even in the Q4 of 2019, we announced that we have 9 rigs. We want to start the year January 1, 'twenty with 6 rigs. So we're very proactive even in the 4th quarter to protect this free cash flow. I mean, little did we know it become more and more and more important. That's why we go from 6 rigs to 5. And then as Roland mentioned a little earlier, we're 4 rigs. So we can toggle that back if we need to. That's where this 95% of our acreage is HBPed and we operate 91% of it. All those are big components that allow us to guide us through this environment. So our goal again is to create value by adjusting this budget if we need to and hopefully you've seen us demonstrate that in the past. Yes, absolutely. I'm sorry if I missed that earlier in the call. I got disconnected for a while there. Yes, thank you for joining. Again, it's a crowded day. Yes. And then for my second question, on the borrowing base, obviously, any reduction is not what you're looking for. But all things considered, when you look at what's happened kind of across the space to some of your peers, You've still got what you're still left with $150,000,000 in liquidity at the end of the quarter. And then in my model, I mean, I've got you generating about $150,000,000 over the remainder of the year. So first, I assume that all that free cash goes straight to the revolver introducing that. And then second, how are you thinking about ways to maybe further reduce that beyond the free cash flow? Or is that just kind of the strategy at this point just to harvest the cash and keep just chipping away at it? Yes, I think that as you pointed as we pointed out, there is a very significant decline in prices even though we had nice growth in our as you saw from the year end report, nice growth in our proved developed producing reserves, but such a large reduction in prices, which were below the bank price decks are well below the strip prices during for the spring redetermination. And so but I do think we've seen the low the worst of that. I mean, I think we've already seen 2 of our major banks start to raise their gas price decks and then lower their gold price decks further. So I think there's a bigger separation going forward. So even a small increase in the gas price decks they use can have a significant add a significant amount to a borrowing base that maybe we'll see in the fall. So we do think that the borrowing base has a lot of potential for growth as gas prices as they start getting closer to what the market is already showing for gas in 2021. But we are going to use the free cash flow to restore the liquidity that we had before the reduction to the borrowing base. That's always the plan. And we think that will be will put us in good shape. And then obviously, we'll at some point, our goal is to we have an overall goal of getting leverage below 2, and we're just a little bit we're a little slightly above 3x levered now. So I mean our goal will be overall to continue to focus on the balance sheet and focus toward getting toward that goal. And stronger gas prices will help a lot next year. And then and so I think that I think we've got a good plan and we'll continue to kind of execute on that. Yes. The one thing that came out in our bargain based review was that the gold standard is that you really have true free cash flow while you have a little growth. And we do have that $150,000,000 to $200,000,000 of true gold standard free cash flow while growing our production maybe that 6% to 8%. So some have free cash flow, but they have no growth or they have negative growth. And so that was I think tested. And I think the second thing I would answer, 73% of this company is owned by the Jones family. They have never been more excited about the growth and the opportunities. And I think that's always something important that the shareholders need to know that they have not lost their enthusiasm at all. In fact, they're probably peak enthusiasm right now because they're very opportunistic. And we I think we as a company, we're prepared for the cycle we're in. We've got the right assets, right people, the right cost. The opportunity is there and we'll seize it. So and I think the banks trust us for that. Our next question is from Phillips Johnston with Capital One. Please go ahead. Hey guys, thanks. Last quarter you guys obviously cut the planned rig count for the year. Obviously, you mentioned improved macro backdrop since then. I know the main goal continues to be free cash flow generation and pay down on the revolver and it's probably a bit premature to talk about accelerating activity. But what would you need to see to add 1 or more rigs back to the program at some point either later this year or next? Well, I think that's a good question and I'd say that's a first time people started talking about that. But the I think you still have relatively low gas prices. So I don't think you try to front run the improvement we see in the curve. And but I think that as we assess next year, we do see probably a little higher activity level just based on the hedges we've already put in, I think we can support a 6 to 7 rig program. And so as we look ahead to next year, we probably see a higher activity level, but won't commit to that and or implement that until we're really in realizing prices that are much improved prices from where they are right now. The reason I love that question is because it shows that you look out into late 2020, 2021 and we get to talk about our almost 2,000 net locations that we have in the same prepared with this inventory that we have that we've demonstrated by drilling these on the 2 30 plus locations, drilling and completing them since 2015. We're prepared for the future. We just need to have a little bit of higher gas price and we need to pay down more on our RBL facility. We do need to get that pay down a little more. Yes, that makes sense. And then Jay, I guess, maybe if we can just get your latest big picture thoughts on industry consolidation in the Haynesville, especially given what's happened in the last couple of months with obviously much lower oil prices, but that improved macro backdrop on gas possibly over the next couple of years or so? Yes. Again, we look again, in the world, you always have have and have nots, and we've all been on both sides of that. We've been on the have not side for a long time with natural gas. I think when the Joneses came in, I mean, he's very good about looking around the corner. You got to look around the corner to be where he is. And as we looked around the corner 2015, 'sixteen, 'seventeen, he looked around the corner of 'eighteen and we said, we, right or wrong, we really want to be a natural gas company. And that's where Ron said 97%, 98%, 99% of our production will be natural gas. And then we had to say, well, it's like location, location, location, not only drilling locations, but geographically where are you located and where do you have this midstream that's a plus to you, not a negative. So as the Joneses look around the corner and we were there hopefully showing them what we're seeing you end up with today. And I think today, I do think that we've got 13,000,000 barrels of oil in the U. S. You probably have 5,000,000 of that in Texas. You see, you've got 750,000 oilfield workers in the U. S. You probably have half of those in Texas, and you're saying maybe half of those are going to lose their job. It's a very tough market out there for oil. And usually, it will take $40 plus for you to really want to drill oil for oil. So we look at that, and we have to look at the oil side model before we look at the natural gas model. We look at natural gas, and we do look at LNG. We say, maybe we lose a Bcf or 2, but there is still a huge demand for LNG. There's a huge industrial demand. Fortunately, the commodity that we have is it's not a transportation commodity like oil is. So I think it is. It's cleaner on the carbon side. We think it's needed. We think it pushes coal out of the way a little bit and it's probably a $3 a $2.80 to $3.15 commodity. That's kind of the price range we look at. And you ask where we would get it really excited. You get a $2.80 to $3 gas price. Our cost structure with our opportunities we have, we're super excited. We just want to maintain where we are. We want to get better with where we are. We want to demonstrate to the bondholders and the equity owners and our stakeholders that we can manage this. And but we think there's some tough times. We don't see $22, dollars 23, dollars 32, dollars 33 oil curing the problem for the oil side of the cycle. And we think as this associated gas goes away, these pipelines were not built to service these oil fields that we only become stronger. And I think we've become a little supercharged because of where we're located. Our economics scream that we are high margins and low cost producer. So that is our corporate attitude. I think that's the Joneses' attitude. All right. Sounds good. Thanks guys. Thanks. And our next question is from Jane Trotsenko with Stifel. Please go ahead. Hey, this is William Howe asking on behalf of Jane. You guys talked about completions cadence a little bit. Could you touch a little bit on CapEx and production cadence for the remainder of the year? Sure. And I think given that completions are more than half of the cost of these wells, we do see that the second quarter being the largest CapEx quarter and hopefully a good free cash flow generating quarter. And then probably so it's not going to be a balanced spending for the rest of the year. I think that you'll probably see the Q2 the lightest and then you kind of after that kind of split the rest of the CapEx between the last two quarters as we if we kind of return to the completion activity in Q3 like we currently plan to. Got it. Thanks. And then my other question is, could you comment a little bit on the industry activity levels that you're seeing in Haynesville? Sure. I think we've seen most of the other companies in the Haynesville are private that are actually running rigs other than a few. And we do see that trending down a little bit. We've seen a few rigs dropped. I think the play the activity level in the Haynesville is kind of a testimony to just how strong the economics are of these wells. I mean, if you look at the basin, I mean, the basis differentials are very, very tight. Transportation is very inexpensive unless you've got unless you've contracted to way above market rates, which we're blessed not to have. So I think the activity level in the Haynesville is a little more resilient than some other plays because of the strong IRRs that you have with the wells. But given that capital is tight for everybody and I think nobody I think most of the operators for the most part want to spend within cash flow or under cash flow and so that is we've seen the larger, but maybe one of the larger private operators really kind of pull back in kind of within their cash flow level. Today, you have 31 rigs that are busy in the HaynesvilleBossier. You have one private equity backed company that has 8 rigs. You have 4 companies that have 4 rigs, and we're one of those 4. And then the rest of them, they may have 1 rig or 2 at the most. So it's 31. That's the last kind of account number we looked at. Got it. Thanks. And then just lastly, should we maybe model in slightly lower Bakken production volumes given the pricing up there? Yes, that's what Ron had alluded to that basically we don't we have not seen it. We've seen reports of about 20 percent of our Bakken production being shut in, but we're kind of modeling 40% shut in just for the rest of the year with that returning next year. And frankly, we wish it was all shut in, I mean, because the prices are so low that there's really that shut in number has no impact on cash flow. In fact, they'd rather preserve the reserves. But we don't we're all not operating on the oil side and have a lot of different operators. So I mean, basically, I think if you kind of track if you cover the bulk and kind of see an industry trend there, you could probably apply that to our oil production and probably close because we're we kind of have non operated interest probably with all the major Bakken operators kind of spread out. So we're that's a good proxy. Got it. Thanks for the color. You bet. Thank you. And our next question is from Willis Fitzpatrick with SunTrust. Please go ahead. Hey, good morning. Good morning. The Shannon production volumes that you guys highlighted, they ticked up a little bit obviously. Are those largely due to the 3rd party offset fracs or is that something you control? And with the reduction in basin activity, do you expect that to kind of tick back down to that sort of 2%, 3% that you've been in in quarters past? Yes. This is Dan. So we approximately 3 quarters of the shut in production we had in Q1 was due to offset frac activity. And I'd say probably the biggest change in Q1 versus the previous quarters is a big majority of that was probably more than we usually average was due to offset operators. They just had a lot of activity nearby our acreage, some of our better production that we had to shut in. We did have a fairly large project we did over in the Elm Grove area that had a that's a really good area. We had to shut a lot of our good production in for that project. So it was definitely an abnormal quarter in that regard and we do see that being much lower for the rest of the year, definitely in Q2. The good thing about what you see there is the quality of these wells that we've been bringing on, you see the sensitivity because these are really high producing rate wells. And any offset operator, they shut in, we shut in, you can see this impact. The beauty of it is that it's not because we don't have quality wells because we do have quality and you can see the sensitivity. So that's a good thing you can see it. I think we've cured it for the most part. And the rig count has dropped from the 50s down to the 31. And a lot of these companies are doing what we're doing. They're kind of waiting on completions. So what I'd add, we've got more than adequate takeaway. And regional basis differentials are really nice and tight. So it's not a it's really just the frac activity and that will be especially in the as we go into May June, we'll be at a pretty low level. So we expect to get back to kind of normal kind of shut in levels, which are closer to that for us 2% to 3% versus the 5%. Okay, perfect. Yes, no, certainly better shut ins than what some of your oil weighted guys are seeing. Yes. That was my point. Yes, that's a great way to say it. Thank you. We do produce a little oil just outside of the non operated part and that is more in our more on the East Texas side and maybe with Cotton Valley and other type production is pretty small. But we have good storage capability. So we don't even want to sell that. So we will for operated oil, we're going to kind of just store that. So over the next 2 to 3 months and not just give it away. Understood. And then it seems like the lateral length also crept up in 1Q, obviously, it's great for capital efficiency amongst other things. Should we expect those kind of longer laterals moving forward or was that just a little bit of noise? No, I think that generally and you can see that on our CapEx slide, you can see that the the as you and if you kind of look at the progression, you can see the lateral lengths are lengthening because as we had a little lower program, I mean, we obviously focused on the longer laterals. They have the best returns and even the wells drilled at year end, they're the longest. So I think you'll see the lateral lengths increasing kind of like the Q1 was a good proxy. So really closer to averaging in the high eight to 9000 feet per well. So usually we only do a shorter lateral if it's just something that's needed to kind of finish up an area and it's the only real way to it's already established where you can't create a long lateral in the future. Thanks so much. And we have no further questions at this time. I guess in closing again, as I mentioned earlier, it is a pretty crowded agenda. So those of you that are still here, thank you. Our commitment to you, our stakeholder is to continue to manage this business properly. They're very difficult times. We're going to be patient. We are going to seize opportunities as they surface and they make us a better company. So thank you for your time and thank you for your trust. Thank you again for joining us today. This does conclude today's conference call. You may now disconnect.