Earnings Call: Q1 2019

Apr 30, 2019

Welcome to the CNX Resources First Quarter 2019 Earnings Conference Call. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Tyler Lewis, Vice President of Investor Relations. Mr. Lewis, please go ahead. Thanks, Anita, and good morning, everybody. Welcome to CNX's Q1 conference call. We have in the room today Nick DeIuliis, our President and CEO Don Rush, our Executive Vice President and Chief Financial Officer Tim Dugan, our Chief Operating Officer and Chad Griffith, our VP of Marketing and President of CNX Midstream. Today, we will be discussing our Q1 results and we have posted an updated slide presentation to our website. To remind everyone, CNX consolidates its results, which includes 100% of the results from CNX, CNX Gathering LLC, CNX Midstream Partners LP. Earlier this morning, CNX Midstream Partners, ticker CNXM, issued a separate press release. And as a reminder, they will have an earnings call at 11 am Eastern today, which will require us to end our call no later than 10:50 am. The dial in number for CNXM call is 1-eight eighty eight-three forty nine-nine ninety seven. As a reminder, any forward looking statements we make or comments about future expectations are subject to business risks, which we have laid out for you in our press release today as well as in our previous Securities and Exchange Commission filings. We will begin our call today with prepared remarks by Nick, followed by Tim and then Don, and then we will open the call up for Q and A where Chad will participate as well. With that, let me turn the call over to you Nick. Thanks, Tyler. Good morning, everybody. I'm going to make most of my comments in reference to Slide number 3 in our slide deck, which is an executive summary for the Q1 and looking forward to the path ahead. You'll see on that slide there's 5 main themes. They're all important. We're going to highlight each of those. And again, I'd like to spend my time covering those before we give it to Tim Dugan and Don for additional commentary. So the first theme on Slide 3, we continue to execute, had another successful quarter of cost and margin performance. Those drove strong risk adjusted returns across our entire portfolio. We hit production targets. More importantly, we hit the production targets by continuing to deliver exceptional cash costs and basin leading all in cash margins. We posted operating cash margins of 63%. When you look to fully burdened cash margins, we posted them at 46%. Both of those are exceptional for any commodity business including of course natural gas. Now strong as those were, I'll tell you too that our expectation is to do better on costs as our activity set continues to benefit from low cost Utica production and from economies of scale. The production, the cash costs that I just spoke about, our hedge book, all of those things delivered cash flows that allowed us simultaneously grow at high rate of returns to reduce our leverage ratio and to reduce share count. So just like Q4 last year, being able to perform all three of these things in the Q1 of this year, that's very powerful when you're looking at intrinsic value per share. Let's start talking a little bit about the second theme on Slide 3 and that is how we are adding an incremental activity to our prior discussed minimum activity set for 2019. The incremental activity add is driven by increased confidence in the rates of return that we see on our Utica opportunity set and it's the things that we highlighted in the earnings release. So it's the Central Pennsylvania Utica data set, which continues to grow and continues to look good. We've got a good run going on drilling efficiencies in the Southwest PA Utica region. And of course, that's an important driver when it comes to what drilling complete cost ends up being. And we're also refining our completion designs for the Utica in ways where we think that's also going to help on the drilling complete capital side of the equation. So those operational developments when you put them together with the robust 2020 hedge book that we put in place, it puts our risk adjusted returns in a zone that warrants the incremental activity. Still emphasize that the most important thing we're looking for before jumping further into the Utica program is a decent production data set for Southwest PA Utica. That's going to of course help refine type curve and we should start to see that data coming in the fall of this year. So that will substantially improve accuracy on capital allocation and rates of return as we discussed on the last call. So the growing confidence in the Utica along with that low cost structure and hedge book, it leads to the 3rd theme on that slide, which is updating our 2019 capital guidance. Most of the net activity add, it comes from the Utica. Our average incremental drilling complete capital is around $13,000,000 per additional Till. We'd like to also point out our investment in what we call other It's a crucial contributor to maintaining and expanding our base and leading margins into the future. So that's our acreage bolt ons on the land side. That's water infrastructure, which includes the line that we're building from the Ohio River and it's also of course midstream. On the midstream side, the all important 2019 build out for the Stack Pay opportunity set, that's well on its way. In fact, it's slightly ahead of schedule from the last time we spoke. And we're pulling spend that was projected for 2020 into 2019 to complete that midstream build out sooner. So that means significantly lower capital in midstream, both CNX attributed as well as CNX Midstream for 2020 when you compare it to 2019. And that also means substantial optionality for 2020 beyond 2020 that will be created by the completed midstream and water infrastructure build outs this year. 4th theme on the slide really speaks to the results of the new 2019 capital and activity set. Now of course much of the capital spend associated with the additional activity that's going to take place in 2019, but the production benefit shows up in 2020. So if you look at 2019 and you look at 2020 and assume our 2019 capital program along with an additional $165,000,000 of 2020 capital that will be used to tie in line the DUCs left from the 2019 program, a few conclusions jump out at you. First conclusion, production for 2020 is going to be about 10% higher than the midpoint of 2019 production guidance. 2nd conclusion, that production when you couple it with the cost structure and the hedge book, it will generate substantial free cash flow. Now that means free cash flow positive for 2019 2020 cumulatively, as well as about $500,000,000 of free cash flow in 2020 only. And all of this assumes by the way the forward NYMEX and basis strips on our open volumes beyond the hedge book, not prices or some arbitrary price deck above the current strip. So as to what we end up doing with that free cash flow, too early to tell, but I can give you some insight by thinking about the big three options. Of course, we could allocate the free cash to debt reduction and end 2020 at leverage ratios in the ones. We could invest in incremental activity and see cash flows in 2020 and beyond grow even more, or we could apply the free cash flow to share count reduction, keeping in mind, dollars 500,000,000 represents 25 percent of our current market cap today. The answer will likely be some combination of these 3 and obviously we're excited about the opportunity to allocate the cash to optimize intrinsic per share value. I want to wrap up with comments on the last theme, that last drill on the table in Slide 3, speaks to not just the Shaw event, but more broadly on how CNX is methodically mitigating and reducing risk. Just a year and a half into the journey as a standalone E and P, CNX is now a top 10 natural gas producer in the United States. And when you think about it, we've only just scratched the surface with respect to the long term upside of our company. So depending on how timing of capital allocation plays out, wouldn't be surprised to see our ranking move up even further. And with that opportunity comes a lot of responsibility, especially in an industry where extraordinary scrutiny is a fact of life. So the imperative to live and breathe a core set of values, it's second to none in our list of priorities. We embrace it, constantly obsess over ways to minimize risks and in our business just like in life, how you respond to the challenges really defines who you are. Now last quarter, we had a challenge and it presented itself to our team and that of course was the Shaw 1 g Utica Shale well in Westmoreland County, where we experienced a pressure anomaly during completions. Following the successful remediation of the Shaw well and a comprehensive investigation, we believe the casing breach was caused by a confluence of a couple of things, environmental factors, pressures and a material failure and the type of pipe that was used in the well. So Shaw 1 gs is currently in the process of being permanently plugged, 4 drilled but not yet completed wells, including 3 on the Shaw pad contain the same casing as the Shaw 1 gs. The casing on those 4 wells will be isolated through the use of a liner, which effectively serves as an additional string of pipe before completion operations are commenced in order to ensure the integrity of pipe moving forward. As a precautionary measure, on a forward looking basis, we have ceased using such pipe across our operations where the identified combination of environmental factors and pressures could be present. And per our updated guidance and subject of course to final DEP approval, we expect to complete the remaining Shaw wells on that pad in 2019. So responsibility, it's first on our list, the values for a reason and that's why we extended the investigation on Shaw 1 gs well across our operations. We don't manage the company by the day, the week or the quarter. We're focused on the long game, getting the generational opportunity right and trading lasting value for all the stakeholders that we touch. And because of the comprehensive efforts, we've reduced our risk profile and enhanced our confidence in our Utica program. Those are obviously good things. With that, I'm going to turn things over now to Tim Dugan and he is going to talk a little more in detail about our operations. Thanks, Nick. Good morning, everyone. Looking at Slide 4, production in the Q1 was 133 Bcfe or 3.5% increase over the same period last year. As expected, volumes declined modestly compared to the Q4 last year as the 2018 development program peaked late in the Q3. Marcellus volumes increased almost 35% year over year as most of our development activity remains in the core Southwest PA Marcellus area. Utica volumes declined about 30% compared to last year because of the divestiture of our joint venture assets in the Ohio Wet Utica. Now looking at costs, we continue to see strong quarterly production cash costs and cash margins of $1.11 $1.86 per Mcfe, Fully burdened cash costs, which include production cash costs plus all other cash expenses, declined 6% compared to the Q1 of 2018, while full burdened cash margin improved by 6%. And also of note, Utica production cash costs were just $0.47 per Mcfe in the quarter. Our cost performance continues to be driven by relentless attention to lease operating expenses and our advantaged transportation, gathering and compression profile compared to peers. We expect this cost advantage to become even more critical over the next couple of years facing a backwardated strip pricing environment. Now looking at Slide 5, we turned in line 18 wells in the Q1, all of which were in the Southwest PA Marcellus. At the end of the quarter, we are running 5 horizontal rigs, 2 in Southwest PA Marcellus, 2 in Southwest PA Utica and 1 in the West Virginia Marcellus. As Nick mentioned, we did add some incremental activity to the prior minimum guidance, which the majority is additional deep Utica wells. At year end 2019, we expect to have turned in line 62 wells and have started activity on an additional 24 wells that will turn in line in 2020. Those 86 wells compare to the 72 wells highlighted last quarter. One thing to point out, last quarter, we highlighted that we expected 12 Utica turn in lines across 2019 2020 and we now have 18. The 12 Utica wells included a 5 well pad in Monroe County that is now being deferred and replaced with Pennsylvania Deep Utica wells. So our Deep Utica well count is actually up by 11 wells out of the 14 well increase. This addition of deep dry Utica wells should highlight our continued excitement regarding the prospects for the Utica formation and its impact on the future of CNX development. Slide 6 highlights our 2019 development program and capital. This is an update of what we provided last quarter. The main takeaway here is that we now expect to turn in line 86 wells across 20 19 20 combined for approximately $885,000,000 in D and C capital, which includes approximately $15,000,000 related to the Shaw event. This compares to the $700,000,000 of D and C capital for 72 wells we highlighted last quarter. The table at the bottom of the page helps reconcile some of the planned changes. With this updated guidance, we're adding 11 deep dry Utica wells and 8 Southwest PA Marcellus wells. However, we have deferred 5 Monroe County Utica wells, which were in the previous guidance. If you look at the summary table, it appears that we're only adding 6 Utica Wells, but we are in fact adding 11 deep Utica wells. Moving on to Slide 7, let's look at some of the highlights from the core Southwest PA Marcellus area. As I mentioned, the majority of our activity has been in this piece of our portfolio and specifically in the Morris and Rich Hill areas. Both fields have legacy wells that we're able to use as a comparison for our latest batch of activity. Across the board, we're seeing improved operational efficiencies and higher EURs. As an example, in Morris, our EURs have increased more than 110% from the legacy wells turned in line back in 2012 2013. In Rich Hill, EURs have increased by about 35% when compared to the much more recent legacy wells turned in line in 2015 2016. But most important, these new wells in both fields are flowing at or above our expected type curves. A similar story can be seen on slide 8 where operational efficiencies and EURs have both improved in our Ohio dry Utica Switz field, where we have a couple of remaining pads left to develop. We expect to apply some of the recent lessons to the new locations. That includes optimized proportions of specialty sands, total sand per foot and inter lateral spacing. The other advantage of the Ohio dry Utica development program is that it has provided a range of insight that can be applied Southwest PA and CPA deep dry Utica programs. Data on optimal lateral spacing, sand loading and specialty sand mixes are invaluable to the field and completion design schemes being implemented in Pennsylvania as we speak. Now on Slide 9 is the Perfect Pad concept that we first introduced at our Analyst Day in March of last year. In the last 13 months, we've begun seller technology for subsurface wellheads is being used on 11 pads where return trips are planned, which drives savings related to Stackpay development. Our 3 d seismic data set drives decision making on where to place laterals as well as how to execute the drill plan. The high pressure, low pressure 2 pipe gathering system is under construction in the Rich Hill area, which will facilitate our full scale stack pay blending strategy. And lastly, I'd add that we've updated our acreage by type curve area in net developed locations that ties to the figures released in our 2018 10 ks. The only major change from last year is that the Ohio wet Utica area has been divested as reflected on the map and these slides can be found in the appendix. With that, I'll turn it over to Don. Thanks, Tim, and good morning, everyone. Slide 10 reflects some of the financial results of the quarter. Consolidated adjusted EBITDAX for the quarter was $268,000,000 or $1.37 per outstanding share. And standalone EBITDAX plus distributions in the quarter were $224,000,000 or $1.15 per outstanding share. Slide 11 highlights 4 important accomplishments in the quarter. First, our leverage ratio now sits at 2.1 times when looking at standalone net debt over trailing 12 month standalone adjusted EBITDAX plus our CNXM distributions. 2nd, we further reduced our share count in the quarter. Since the inception of the program in the Q3 of 2017, we have bought back approximately 15% of the outstanding shares of the company. 3rd, we completed a $500,000,000 senior notes offering to term out some of our debt, paying down our 2022 notes by $400,000,000 and our revolver by $100,000,000 Lastly, after the close of the quarter, as we announced today, we amended and extended our credit facility, while reducing our rates by 25 basis points in the process. Now let's shift to our updated guidance. Slide 12 provides an overview of the major changes in guidance compared to last quarter. 2019 production volumes remain unchanged at 4.95 Bcfe to 5.15 Bcfe for the year. And as you can see, we are adding incremental activity and our D and C is up for both 2019 and the bleed over capital flowing into 2020. This incremental activity generates incremental rates of return and really sets us up for 2020 extremely well, as Nick stated earlier on the call. Our non D and C increased slightly to $200,000,000 due to a variety of investments that support the incremental activity. I will let CNX Midstream discuss their capital increase on their call following ours. But as everyone knows, we consolidate their results in our financials, which is why we are showing their capital of $310,000,000 to $330,000,000 on this slide. As for adjusted EBITDAX on both a standalone and consolidated basis, we essentially did a mark to market and saw these estimates come down due to a decline in natural gas prices since our last update. Slide 13 provides more detail on revenue and cost line items. As you can see, we now expect some modest improvements in SG and A and other operating expense this year. Slide 14 provides a couple of updates. To start, it shows our updated production forecast. At a high level, we expect 2019 production cadence to follow a similar pattern we observed last year, with volumes moderating through the 2nd and third quarters and then increasing in the 4th quarter. With that, we expect our 2019 exit rate to be approximately 9% higher than 20 eighteen's. This program is executed with the rigs rolling off towards the end of the year and we would end the year with 3 rigs running. Decisions to keep rigs or not will be made as the year unfolds based on a variety of factors such as gas prices at the time of the decision and other capital allocation options. Also, this slide illustrates what we are getting in 2020 for the incremental capital we are spending in 2019 2020. Assuming only this activity, we would expect 2020 volumes to grow by approximately 10%, which will position the company to generate over $500,000,000 in free cash flow. The table on the slide walks you through a general buildup to show it. And as highlighted in our press release this morning, we expect to deploy that free cash flow across 3 options incremental 2020 activity at high internal rates of return, debt reduction and or additional share buybacks. And if history is any indicator, we will likely utilize all of these options. Another important factor I would like to point out on this slide is that we are using the current real forward strip for 2020, not a forward price assumption that is higher than the current strip. And as you can see from the slide, most of our volumes in 2020 are derisked through our hedging strategy. So to put it simply, if the strip stays the same, we generate significant free cash flow as we have laid out on the slide. If gas prices get worse, we still generate significant free cash flow. And of course, if gas prices end up higher than the current forward strip, we generate significant free cash flow. This reality is unique to CNX. Our strong hedge position can be found on Slide 15. And as you can see, we continue to programmatically layer on hedges and now have 440 Bcfe of fully covered hedges for 2020. Slide 16 provides some additional color on our water assets and how water management is competitive advantage for us. It is a great platform that reduces our lateral cost per foot, generates third party cash flows and has significant growth opportunities. CNX is at the forefront of fresh and produced water services. Our infrastructure is already moving 3rd party produced water and will move more as water becomes a bigger issue and topic across the industry. I will conclude on Slide 17, which is a reminder that we have a nice tax refund in 2019 of which we received $36,000,000 of the $146,000,000 forecasted in the Q1. With that, I'm going to hand it back over to Tyler. Thanks Don. And operator, if you can open the line up for Q and A at this time please. Thank you. We will now begin the question and answer session. Our first question today comes from Welles Fitzpatrick with SunTrust. Please go ahead. Hey, good morning. Good morning, Walter. Good morning. Yes, I guess, I mean, and you noted this in your prepared remarks that the decision to keep rigs and whatnot to the fact that 2020 is really just DUCs and sort of what happens in 2021 if you execute on the program as described in the presentation and the press release? I mean would that your corporate decline rate kind of match almost the hedging profile that we see on Page 15 or how do you think about that? Yes. So we did lay out our production wedges on 14. As you can kind of, I guess, generally triangulate the 2021 volumes are in the zone of where our hedges are as we've laid out our strategy of protecting the incremental investments with hedges to ensure that we are getting the risk adjusted returns that we're expecting to get and the gas price change won't affect it. As for what we do in 2020, we've tried to kind of not get caught at a calendar year cutoff in 2019. So the bleed over capital to complete the work in progress is in there for 2020. What we do on top of that will be dependent on what gas prices and other things are in 2020. But as Nick said earlier, the balancing act of how much you put in each of the options we have that deploy the cash flow is really the decisions we'll be making in 2020 to ensure that 2021 and several years in front of that is a healthy business, a healthy capital structure and the most important piece is just ensuring you make incremental returns for incremental capital that you are spending. Okay. That makes total sense. And then to kind of I mean trying back almost into to more sort of a run rate free cash flow yield. If on 2020 you exclude the ATM payment and you included the sort of drill costs on those 24 wells, again, almost as a theoretical way to look at capital efficiency. Would you think the free cash flow, I mean, is it going to be somewhere in I'm coming at kind of $300,000,000 $350,000,000 Is that about right? Yes. I mean, obviously, one of the big factors is what the gas price is going to be in that year and what we've tried to very I guess thoughtfully layout is we're using the current forward strip. If you look a lot of folks are using price points significantly higher than that current forward strip. So if you're using those kinds of price levels the free cash flows would be significantly more, but generally, I think you can kind of triangulate to an area that you're in looking at the way you described. Okay. That's perfect. And just one more, if that's okay. Maybe I'm reading a little bit too much into it, but the great extra detail on Slide 16, it kind of seems like some bread crumbs that we could use to get to where the EBITDA might be on that system, which the natural inclination old MLP multiple on it. Are you kind of guiding us in that direction or is that really just sort of incremental detail for the sake of itself? Yes. I think some of this stems from our last call and conversations we've had since and just understanding some of this other spend and what it's for and what it does for the business. Water is a strength of CNX. It is something that we feel is not just a one time short term investment. It is setting us up for very long capital efficient development for several years. And I think it's kind of hidden a little bit. So we wanted to really highlight what that spend really gets you and the fact that it is a profitable business model that more and more folks, it's been topical here recently. We just wanted to let the investors know that we're kind of ahead of the game and kind of get into a water model that not only works for CNX, but could be could work for the region and other third parties as well. As far as how that business is set up and where it goes, lots of things to be figured out there. So no guidance on that front. Just the fact that it is a great asset both for our company and potentially for generating incremental cash flows over and beyond that as we move forward. Very helpful. Thank you so much. The next question comes from Holly Stewart with Scotia Howard. Please go ahead. Good morning, gentlemen. Maybe Nick, if you could talk a little bit about on Slide 3, which you sort of went through in detail, but you talk about an operational reevaluation. So if you could just maybe share some thoughts on that process and the changes, maybe to some of your best practices that you're doing differently and maybe this ties into that casing liner that you mentioned. So if you could talk about that as well? Sure. There's really different components there of what we went through. There's with respect to the Shaw 1 gs itself and addressing that issue and then wrapping up the plugging operations on that which should happen shortly. Then there was the second piece of this is the Utica wells in the current portfolio, 4 in particular, 3 of them on the Shaw well that had utilized similar pipe and making sure that we're beefing those up and removing any risk that we may see with respect to those by putting aligners into the vertical sections of those pipes. Then there's the QAQC piece of just moving forward, all the ancillary benefits or improvements or refinements that we found, whether it's Marcellus or Utica with respect to how we're going about drilling, completing and producing those wells moving forward. And there have a series of what I'd call tactical improvements that we've identified through this effort and we extended it beyond the Shaw and frankly beyond the Utica. So those are sort of the 3 big components of this and it's the last one I think that's the most long term and will impact D and C and capital efficiencies the best. But that's how I break them down and I don't know if Tim wants to add anything after that. No, it's just following up on what Nick said a little bit. We have revised some of our best practices and primarily they're around our casing, everything from manufacturing through handling and installation. It's really just kind of fine tuning what we've already what we already do. But as with any improvement we find, we look at whether or not it applies to other areas of our operation. So we've taken an in-depth look and made some modifications to some additions to best practices and also made some modifications to our casing design. But it's really that's we talk about continuous improvement and this is really just part of it. Okay, that's helpful. Maybe one for Chad on just the basis guidance, it looks like you're still guiding to $0.20 to $0.25 after roughly $0.17 in 1Q. So anything just out there in Appalachia that you're seeing today on the basis market is kind of giving you the confidence that this sort of basis level continues going forward? Yes, I think a lot of it has to do with the expansion pipelines that come online over the last really over the last year combined with really all of our peers slowing down. This really set the stage for there's capacity to move gas out of the basin and so really basis is moving towards sort of variable cost to move that gas. And so that's sort of what sustains that sort of longer that reaffirms that basis for 2019. The next question comes from Joe Allman with Baird. Please go ahead. Thank you. Good morning everybody. So I've got a follow-up on the shawl 1 gs. One of the factors you mentioned is environmental. Could you just elaborate on what you mean by environmental factors? And how do you know about those factors before you drill the well? Well, we did a pretty thorough review of the Shaw incident and brought in a lot of independent experts to help us out with that. And really majority of the data and information pointed to a material failure that was caused due to the high tensile strength pipe that was being used when exposed to certain environmental conditions. That pipe tends to become brittle and is more prone to environmental stress cracking. Some of the environmental conditions, there are certain temperature ranges, the presence of hydrogen that can lead to that. But these findings, it wasn't just something that we came up with ourselves. We had independent experts working with us and confirming and providing thoughts and data to confirm what was being found. Okay, that's great. And then just to confirm, so it sounds as if you might use the same casing in certain circumstances, but in other circumstances where the same environmental factors might exist, you're going to use different casing? We have modified our casing program going to a more put it simply a more ductile pipe that is not prone to embrittlement. But there are areas that like in our laterals where the temperatures and the pressures are not an impact and the brittleness is not an issue, we may use some of this pipe. But we have changed overall we've changed our casing design. Okay, that's helpful. And then earlier in the call you mentioned a different topic, the exit rate 9% higher in 2019 versus 2018. Could you just confirm the exit rate? Does that mean 4Q over 4Q or December over December or December 31st over December 31st? That's average December to average December. Okay. That's helpful. And then last one, could you just make some comments, I know you're using the strip for your guidance. Talk about the gas macro, if you have any insights in the gas macro. You just touched on takeaway, so that was helpful. And then you mentioned water, like what water issues are you or others experiencing? And what water issues might you or others experience? Yes, just first on the macro question. We're coming out of winter at really record low inventories and storage. And so really the thing everyone's looking at this summer are going to be the injection rates, how quickly the storage refill over 2019. And that's going to be a huge factor just how hot of a summer that we end up having. Really, I think 2019 and going into next winter and beyond is going to be largely a function of what weather looks like this year and into winter. We've got a lot of incremental supply coming out of the Permian that's being matched with incremental LNG offtake and incremental demand going to Mexico. So sort of a supply demand balance, those 2 are sort of staying in sync. So I think this year's gas price going into next year's gas price really, really comes down to weather this year. We have a mild summer, we have a mild early winter, storage levels I think we get back to sort of where we need to be on storage. But if we end up with a super hot summer that keeps gas from being reinjected, then we might end up with a lower number entering winter. And you might see some really strong prices again next winter. But at the end of the day, I don't think any of us have crystal ball to be able to predict that weather with a high level of confidence. And that's why as we talked about earlier on the call, we continue to programmatically hedge as we make incremental capital investments. We hedge the gas both NYMEX and basis to take that commodity risk off the table. And that way we can continue to sort of shine through our capital efficiency and operational low cost low OpEx. Low OpEx. Yes, go ahead and just follow-up from Chad. I mean, we take the view that if gas prices get better, we can always add activity. But if gas prices go down, you can't unspend the capital. So we try to take a very thoughtful approach on making sure it works in the current strip and not taking a risk both on the investment and the balance sheet and health of the company if our gas prices don't turn out. So if like I mentioned earlier, a lot of folks are using a assumption for 2020 gas price and if it holds great, we have lots of great things we can do. But if the strip turns out to be true or if gas prices go lower than the strip, our balance sheet, our capital structure, our leverage ratios are all still solid. And that's a unique position that we're in that a lot of others aren't if gas prices don't actually get healthier. As far as water, I'll generalize it really in 2 parts. You got the water supply side. That's obviously the Ohio River waterline and how we're approaching this. It's a consistent source of supply if you look and there's been wet seasons and dry seasons. But if you do run into a bit of a dry season, again, predicting weather, it's hard to do. There will be some pinch points on being able to adequately get supply for these fracs and the evolution crew that we established and the rate of water you need on barrels per day, barrels per minute to do the completion jobs that we want. You need a strong supply source and that really helps derisk and sets us up to take advantage of that side of the offense. And obviously, pumping water is much more efficient than trucking it as we laid out on the slide. On the other side, the disposal end, it is sort of a tighter market on having adequate disposal capacity if fracs don't line up properly with flowbacks and produced water volume. So whenever we look at our own business model and we set our plans, we've talked to ensuring that we have a healthy water balance and we can be reusing the produced water that we have and paying very close attention to that. That is something that could again if it gets out of balance, which we've seen happen in a quarter or 2 and everybody's heading to disposal, it gets very costly very quickly. So those the source side and the reuse side are big items that could lead to call it margin producing opportunity going forward. The next question comes from Biju Panitchkar with Susquehanna. Please go ahead. Hi, good morning. Question about 2020 or just the increase in activities this year. You mentioned the high confidence on the cost side in Utica. Can you talk a little bit more about your confidence level on the production side, especially in Southwest Pennsylvania, because that's the area where it looks like some of the wells may not have been quite up to your expectations so far? Sure. If you go to the incremental activity set that we've announced today above the minimum activity set we announced coming off the Q4 call, Most of that as you said is Utica centric or Utica driven. It's about the rate of returns as it's always been. And the factors that have changed over the past couple of months with respect to our confidence in those rate of returns, you can sort of walk through the list. 1st on the hedge book, particularly 2020 2021, being able to take that revenue uncertainty off the table helps us obviously get more confident in the rate of return we're projecting for that incremental capital spend. When you start to get into the Utica centric data, CPA, the Central Pennsylvania Utica footprint region, there the data set grew by another quarter, of course, still looks good. So we've got yet another sort of time period of data to add to what was a pretty significant data set in Central Pennsylvania, which makes us more confident. On the drilling and completion side of things with respect to what it costs to basically turn in line a Utica well, we've also had some positive developments on that front past couple of months. On the drilling side, we mentioned the drilling efficiencies, particularly in the including Southwest PA Utica or in particular with Southwest PA Utica, we're going to be able to see the completion designs including Southwest PA Utica, in particular with Southwest PA Utica, also some refinements where we feel that those designs will help drive drilling complete costs lower. So those are sort of the factors that help give us more certainty or confidence in the rate of return with respect to Utica drilling complete capital. The last piece of the puzzle is the data for the Southwest PA Utica field and that's what's still waiting coming up into end of summer, beginning of fall this year. And really at the end of the day, if you look at our activity set, it's those select wells that we're drilling and completing our pads. They're going to provide the data not just for ourselves, but frankly for the industry. So that's why we basically peg the activity set at the level it's at now and let's assess, see where the data come in, in particular for Southwest PA and then refine update our rate of return calculations and go from there. And to add to what Nick said, we have talked all along about the data set for the Utica, but also how compartmentalized the Utica is compared to the Marcellus. In Southwest PA is compartmentalized. It's not just when we talk about Southwest PA Utica, we're just not talking about one type curve, one set of characteristics. Talked about the geohazards in Southwest PA, the natural fracturing and how challenging that can be and that has certainly been a factor in some of the 2 data points that we have with our wells. But when you look at Nick mentioned drilling efficiencies of the last 4 wells we've drilled in Southwest PA, All four wells have been drilled in that 30 to 40 day range with 2 wells, 1 at 29 days, 1 at 31 days. So our drilling efficiencies have picked up tremendously. We've gained a lot of knowledge on our completion design, which is really helping us move towards that $12,000,000 to $12,500,000 well much quicker. We've gotten in more logs, more cores, seismic data has been critical in being able to place wells properly so that we don't encounter the hazardous natural fracturing that can impact well quality. So and keep in mind Southwest PA, when you look at CPA, we've had a lot of good results. We're much further along in the delineation process and in some areas up there in the main mine area, we're really moving more into production mode. Southwest PA is still in delineation mode. Although there are some other data points from other operators, many of those data points are older. Older completion designs, there wasn't seismic data being used. So you've got to take some of those older data points and use what you can, but they're not always completely representative and we don't have access to all that data. So we continue to build the data set. We are still excited about the Utica, but keep in mind, it is much more compartmentalized than the Marcellus and there are some areas that are more challenged than others, but we are can see from the increase in our activity, we are excited about the Utica. We think it is going to be a significant part of this company going forward and we're going to keep pushing on. Okay. That's very helpful. So if I think about the incremental activity in Southwest PA Utica then would you say there's maybe a little bit more uncertainty or variability on the timing as you get the next batch of data points sort of proving up your thinking on the geology side? Well, the next two data points we get from a production standpoint, we've got a pad scheduled to turn in line in August and one in September. So that production data will be significant and important. But as we continue to drill wells, as I mentioned in my comments, we have 2 rigs drilling Southwest PA Utica right now. We've drilled 1 in Northern West Virginia where we got logs and cores. So we continue to build that data set of logs, cores, geologic data with the seismic alongside the cores and logs. But it builds our confidence and builds our improves our understanding and really each data each piece of data helps us understand and reduce our risk. And then the next question I had was on the 3 rigs you have at the end of will have still on contract at the end of the year. What's the timing of when those three roll off contract? The next one would roll off mid year 2020, but and then the others are beyond that. I don't know the exact dates, but they are beyond that. But as with anything, make those decisions. We are looking at the market and all the conditions, the hedging and price environment and our drilling efficiencies and we make those decisions and so we'll address that. We've got timeframe set understanding when those rigs come up and we'll make sure those questions are answered and addressed in the proper timeframe. Perfect. Thank you. The next question comes from Jane Trotsenko with Stifel. Please go ahead. Good morning. My first question is on 2019 CapEx increase. I'm trying to understand if it's mostly attributable to this additional activity that you guys highlighted 14 additional DUCs in 'nineteen and 2020 or if there are other factors that impact 2019 CapEx? Sure. So there's different obviously different pieces of the build up to capital and we've sort of laid those out in the release and slide deck. But certainly the incremental activity, the 14 TILs are a big incremental piece of that and we tried to itemize that. We've also shown what the changes were in the other category, which again is our land capital, our water infrastructure and our midstream side as well as CNX Midstream's capital because of the acceleration of '20 originally projected 'twenty activity now that we can get done in 'nineteen. So if you're looking at things on a consolidated basis that's another driver. So those are laid out in some detail, but the biggest piece of that is the incremental activity set above the minimum guidance that we discussed on the Q4 call for 2018. That's very helpful. Could you maybe explain why exactly you decided to add incremental activity in 2019 to kind of deliver higher production growth in 2020? What was the motivation for doing that? Sure. This goes back again to the rate of returns driving our decision making. So when we looked at the incremental activity, whether it's the capital or the production that would come from the capital investment, we're ultimately looking at the rate of returns and letting the rest of those metrics become more results versus what we're solving for. We are solving for rate of returns and the risk associated with those rate of returns. So when we look at our hedge book, particularly for 2020 2021, which will be a big determinant, the revenue in the front 2 years of a shale well is going to be a big determinant of the ultimate rate of return just because of the well profile. Being able to take that uncertainty off the table and knowing for certain what the hedge book, what the realizations will be, That gave us confidence in rate of returns. We talked about we didn't say much on this call actually, but we've talked about in the past quite a bit about the Marcellus and we've done some updating of performance metrics in the Marcellus and certainly it continues to perform and frankly outperform. So with respect to well profiles in the Marcellus and then we talked through some earlier questions about the confidence that we're growing with the well profile in the CPA Utica, our drilling complete cost in the Utica because of the drilling efficiencies we've recently seen in Southwest PA and our completion designs that we refined with respect to Central Pennsylvania and Southwest Pennsylvania Utica. You add all of those together, basically the rate of return that we see coupled with the risk or the uncertainty tied to it put us in a position where we believe it's prudent to invest in that capital if we're solving for intrinsic per share value. Okay, got it. May I ask the last question. I'm trying to understand the medium term production outlook. So production outlook beyond 2021, and I understand that you guys do not target free cash flow necessarily. It seems to me that leverage should be the guiding factor. And maybe you can remind us the leverage band that you would like to stand within you to stay within over the medium term, long term? Yes, yes. We've talked to this 2.5x leverage ceiling is the way we think about the balance sheet. What we've also said is it is not just a leverage ratio in isolation. We view our hedges part and partial to our capital structure and our balance sheet likewise are low fixed cost obligations and low cost structure and asset qualities that we do have. So we do look as we laid out in here, 21 is our current trailing 12 months leverage ratio. But we'd like to look out 1 year, 2 year, 3 years, really we want several years of dependable, reliable cash generated from the business when we're setting our capital structure and we do look at it sensitizing for gas prices both up and down and our hedge book really is what gives us the ability to set these targets and have clarity 1, 2 years down the road where most folks don't if you don't have a hedge book to kind of protect the revenue side of your business. Okay, got it. Thank you so much. This concludes our question and answer session. I would like to now turn the conference back over to Tyler Lewis for any closing remarks. Great. Thanks, Anita, and thank you everyone for taking the time to join us this morning. We look forward to speaking with you next quarter. Thank you. This conference has now concluded. Thank you for attending today's presentation. You may now disconnect.