CNX Resources Corporation (CNX) Q1 2019 Earnings Report, Transcript and Summary

Good morning and welcome to the CNX Resources First Quarter 2019 Earnings Conference Call. [Operator Instructions] 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 first quarter 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 first quarter results and we've posted an updated slide presentation to our website. To remind everyone, CNX consolidates its results which includes a 100% of the results from CNX, CNX Gathering LLC, CNX Midstream Partners LP. Earlier this morning CNX Midstream Partners tickered CNXM issued a separate press release, and as a reminder, they will have an earnings call at 11:00 A.M. Eastern today, which will require us to end our call no later than 10:50 a.m. The dial-in number for CNXM call is 1-888-349-0097. As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risks which we've 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&A where Chad will participate as well. With that, let me turn the call over to you Nick.

Thanks Tyler. Good morning everybody. I would make most of my comments in reference to Slide number 3 in our slide deck, which is an executive summary for the first quarter and looking forwards to the path ahead. You'll see on that slide, there is a slide 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 and had another successful quarter of cost and margin performance. Those grow 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 cost and base in leading all-in cash margins. We posted operating cash margins of 63%. We 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 cost as our activities that continues to benefit from low-cost Utica production and from economies of scale. The production, the cash cost that I just spoke about, our hedge book, all these things delivered cash flows that allowed us to simultaneously grow at high rate returns to reduce our leverage ratio and to reduce share count. So just like fourth quarter last year, we've been able to perform all three of these things in the first quarter of this year. It'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 and 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 drove 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 and 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 warrant 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 the 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 return as we discussed on the last call. So the growing confidence in the Utica along with the low-cost structure and hedge book, it leads to the third 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 and complete capital is around $13 million for additional TIL. We'd like to also point out our investment in what we call other as a crucial contributor to maintaining and expanding our base in leading margins into the future. So that's our acreage bolt-on on the landside, 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 stacked pay opportunity set, that's well on its way, exactly 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 to 2019. And that also means substantial optimality for 2020 and beyond 2020, it will be created by the completed midstream and water infrastructure build outs this year. Fourth theme on the slide really speaks to the results of the new '19 capital on activity set. Now of course much of the capital spend associated with the additional activity that's going to take place in 2019 post the production benefit which 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 million of 2020 capital that will be used to turn-in-line that's left from the 2019 program, a few conclusions jump out of here. First conclusion, production for 2020 is going to about 10% higher than the midpoint of 2019 production guidance. Second conclusion at production, when you couple it with cost structure and the hedge book, it will generate substantial free cash flow. Now that means free cash flow positive for 2019 and 2020 cumulatively as well as our $500 million of free cash flow in 2020 only. And all this assumes by the way the forward NYMEX and basis strips on our open volumes beyond the hedge book, not prices or some arbitrage price deck above the current strip. So as to what we end up doing with our free cash flow too early to tell, but I can give you some insight by thinking about the big three options. Of course, if you allocate the free cash to debt reduction and end 2020 at leverage ratios in the 1s, we could invest an incremental activity to see cash flows in 2020 and beyond grow the more or we could apply the free cash flow to share count reduction, keeping in mind $500 million represents 25% to 30% of our current market cap today. The answer will likely be some combination of these three and obviously we're excited about the opportunity to allocate the cash to optimize intrinsic per share value. I'm going to wrap up with comments on the last theme, that last row 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 1.5 year into the journey as a standalone E&P, CNX is now top 10 natural gas producer in The United States. And when you think about with only scratched the surface with respect to the long-term upside of our Company. So depending on how timing of capital allocation plays out, I wouldn't be surprised to see our ranking move up even further. Now with that opportunity comes a lot of responsibility, especially in an industry where extraordinary scrutiny is the fact of life. So the imperative to live and breathe of course had a value, it is second to none in our list of priorities. We embrace it, constantly obsess our ways to minimize risk and our business is just like in life how you respond to the challenges really defines who we are. Now last quarter we had a challenge and it presented itself to our team, and that of course was the Shaw 1G 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 in the type of pipe that we used in the well. So Shaw 1G is currently in the process of being permanently plugged, four drilled but not yet completed wells including three on the Shaw Pad, contain the same casing as the Shaw 1G. The casing on these four 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 movement forward. As a precautionary measure, on a forward-looking basis, we have seized use of such pipe across our operations where the identified combination of environmental factors and pressures could be present. And for our updated guidance and subject to of course the final DEP approval, we expect to complete the remaining Shaw wells on that pad in 2019. So responsibility, it's first on our list of values for a reason, and that's why we extended the investigation on Shaw 1G 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 touched. 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 first quarter was 133 Bcfe or 3.5% increase over the same period last year. As expected volumes declined modestly compared to the fourth quarter last year as the 2018 development program peaked late in the third quarter. 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 cost and cash margins of $1.11 and $1.86 per Mcfe respectively. Fully burdened cash costs which include production cash costs, plus all other cash expenses declined 6% compared to the first quarter of 2018, while fully 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 advantage 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 backward dated stripped pricing environment. Now looking at Slide 5, we turned-in-line 18 wells in the first quarter, all of which were in the Southwest PA Marcellus. At the end of the quarter, we are running five horizontal rigs, two in Southwest PA Marcellus, two in Southwest PA Utica, and one 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 compared 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 and '20, and we now have 18. The 12 Utica wells included a five 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 well 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 take away here is that we now expect to turn-in-line 86 wells across 2019 and '20 combined for approximately $885 million of D&C capital, which includes approximately $15 million related to the Shaw Event. This compares to the $700 million of D& C capital for 72 wells we highlighted last quarter. The table at the bottom of the page helps reconcile some of the plan changes. With this updated guidance, we're adding 11 deep dry Utica wells and eight Southwest PA Marcellus wells. However, we have deferred five Monroe County Utica wells which were in the previous guidance. If you look at the summary table, it appears that we're only adding six Utica wells but we are in fact adding 11 deep Utica wells. Moving on to Slide 7. Let's look at the 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 Richhill areas. Those 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 and 2013. In Richhill, EURs had increased by about 35% when compared to the much more recent legacy wells turned-in-line in 2015 and 2016. But most importantly, 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 in 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 with 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 to Southwest PA and CPA deep dry Utica programs. Data on optimal lateral spacing, sand loading and speciality 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 begun implementing several of the key elements of the Perfect Pad that drive capital efficiencies and improve EURs. For example, Cellar technology for subsurface well heads is being used on 11 pads where return trips are planned, which drives savings related to stack pay development. Our 3D seismic data set drives decision making and where to place lateral as well as how to execute the drill plan. The high pressure low pressure two pipe gathering system is under construction in the Richhill area, which will facilitate our full-scale stacked 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-K. 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 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 million or $1.37 per outstanding share, and standalone EBITDAX plus distributions in the quarter were $224 million or $1.15 per outstanding share. Slide 11 highlights four important accomplishments in the quarter. First, our leverage ratio is now set to 2.1 times, when looking at standalone net debt over trailing 12-months standalone adjusted EBITDAX plus our CNXM distributions. Second, we've further reduced our share count in the quarter. Since the inception of the program in the third quarter of 2017, we have bought back approximately 15% of the outstanding shares of the Company. Third, we completed a $500 million senior notes offering to term out some of our debt, paying down our 2023 notes by $400 million and our revolver by $100 million. 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 495 Bcfe to 515 Bcfe for the year. And as you can see, we are adding incremental activity and our D&C is up for both 2019 and complete 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&C increased slightly to $200 million due to a variety of investments that support the incremental activity. I'll let CNX Midstream discuss their capital increase on their call following ours, but as everyone knows, we consolidated their results in our financials, which is why we are showing their capital of $310 million to $330 million on this slide. As for adjusted EBITDAX on both the standalone and consolidated basis, we essentially did a mark-to-market consolidated investments 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&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 similar pattern we observed last year with volumes moderating through the second and third quarters and then increasing in the fourth quarter. With that we expect our 2019 exit rate to be approximately 9% higher than 2018's. This program is executed would see rigs rolling off towards the end of the year. And we would end the year with three 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 decisions and other capital allocation options. Also this slide illustrates what we are getting in 2020 for the incremental capital we are spending in 2019 and 2020. Assuming only this activity we would expect 2020 volumes to grow by approximately 10% which will position the company to generate over $500 million in free cash flow. The table on the slide walks you through a general build up to show it. And as highlighted in our press release this morning, we expect to deploy that free cash flow across three options; incremental 2020 activity and 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. As you can see from the slide most of our volumes in 2020 are de-risked through our hedging strategy. So to put it simply if the strip stays the same we generated 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 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 third-party produced water and will move more as water becomes a bigger issue in top and across the industry. I'll conclude on Slide 17 which is a reminder that we have a nice tax refund in 2019 of which we received $36 million of the $146 million forecasted in the first quarter. 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&A at this time please.

[Operator Instructions] Our first question today comes from Welles Fitzpatrick with SunTrust. Please go ahead.

Yes I guess, I mean and you noted this in your prepared remarks that the decision to keep breaks and what not would be made at the time. But can you talk to the fact that 2020 is really just stuck 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 matched almost the hedging profile that we see on page 15 or how do you think about that?

Yeah, so we did layout our production wedges on 14 as you can kind of I guess generally triangulate the 2021 volumes are in a 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 gas price change but won’t affect it. As for what we do in 2020 we've tried to kind of not get caught at the county or cut off at 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 - to 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 to deploy the cash flow is really the decisions we will be making in 2022 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.

And then to kind I mean trying back almost and to more sort of run rate free cash flow yield. If on 2020 you exclude the ATM payment and you included the sort of drill cost on those 24 wells again almost it’s a theoretical way to look at capital efficiency would. Do you think the free cash flow I mean is it going to be somewhere and I'm coming to kind of 300 million, 350 million 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 vary 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 we're using those kind of price levels the free cash flow's would be significantly more. But generally I think you kind of triangulate to an area that you're in looking at the way you describe it.

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 aware that EBITDA might be on that system which the natural inclination within EBITDA to put the old MLP multiple on it. Are you kind of guiding us in that direction or is that really just sort of incremental detail for say himself?

Yes I think some of this stem from our last call and conversations we have 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 hitting a little bit. So we wanted to really highlight what that spend really gets you. And in fact that it is a profitable business model that more and more folks it’s been more topically here recently. We just wanted to let the investors know that we're kind of ahead of the game and kind of get into 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.

The next question comes from Holly Stewart with Scotia Howard. Please go ahead.

Maybe Nick if you could talk a little bit about on Slide 3 which you sort of went through in detail, but you talked about an operational reevaluation. So if you could just maybe share some thoughts on that process and the changes maybe 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 is really different components there of what we went through. With respect to the Shaw 1G 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 and the current portfolio four in particular three of them on the Shaw well, did utilize similar pipe and making sure that we're beeping those up and removing any risk that we may see with respect to those by putting the liners into the vertical sections of those pipes. And then there is the QAQCPs 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 been a series of what I call tactical improvements that we've identified through this effort and we've extended it beyond the Shaw and frankly beyond the Utica. So those are sort of the three big components of this. And it's the last one I think that's the most long-term and will impact our D&C and capital efficiencies the best. But that's how I brace them down. I don't know if Tim wants to add anything after that?

No, just following up on what Nick said a little bit. We have revised some of our best practices and primarily they are around our casing everything from manufacturing through handling and installation. It's really just kind of fine tuning what we already do. But as with any improvement we find we look at whether or not it applies to other areas of our operations. 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 it’s a, we talk about continuous improvement and this is really just part of it.

And maybe one for Chad on just the basis guidance, it looks like you are still guiding to $0.20 to $0.25 after roughly $0.17 in 1Q. So anything just out there in Appalachia that you seen today on the basis market is kind of giving you the confidence at this sort of basis level continues going forward?

I think a lot of it has to do with the expansion pipelines that have come online - really over the last year combined with really all of our peers slowing down. It really sets the stage for there is capacity that moved gas out of the basin. And so really basin is moving towards sort of cost to move back to us and that sort of what sustained that so longer, but reaffirms that basis for 2019.

The next question comes from Joe Allman with Baird. Please go ahead.

So I've got a follow-up on the Shaw 1G. 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?

We did a pretty thorough review of the Shaw incident and brought in a lot of independent experts to help us out with that. Really majority of the date and information pointed to a material failure that was caused due to the high tensile strength pipe 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 - 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 on data to confirm what was being found.

And just to confirm so it sounds that 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 - they are not an impact and the brittleness is not an issue. We may use some of this pipe, but we have - overall we've changed our casing design.

And then earlier on the call you mentioned 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.

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 and toil for storage. And so really the thing everyone is looking at the summer are going to be the injection rates how quickly the storage refill on 2019. And that's going to be a huge factor just how hot the summer we end up having. Really I think, 2019 and going into the next winter and beyond is going to be largely a function of what weather looks like for this year and to winter. We've got a lot of incremental supply coming out of the Permian. That's being matched with incremental LNG off-take and incremental demand going to Mexico. And so sort of a supply-demand balance, those two are things to think. So I think this year's gas price going into next year's 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 end up with the superhot summer that keeps gas from being reinjected then we might end up with lower number entering winter, you might see some really strong prices again next winter. But at the end of the day, I don't think any of crystal ball to able to predict that weather with a high level of confidence. That's why as we talked about earlier on the call, we continue to programmatically hedge as we make incremental capital investments we hedged the gas both NYMEX and basis to take that commodity risk off the table. In that way we continue to sort of shine through our capital efficiency and operational low cost low OpEx.

And on the water?

We take the view that if gas prices get better we can always add activity. But if gas prices go down you can't spend the capital. So we try to take a very thoughtful approach on making sure it works in the current strip and not taking the risk both on the investment and the balance sheet helps as a company if our gas prices don't turn out. So if - like I mentioned earlier, a lot of folks were using 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 and a lot of others aren't if gas prices don't actually get healthier. As far as water, I'll generalize it really in two parts. You get 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 whether it's hard to do. There will be some pinch points on being able to adequately get supply for these fracs into evolution crew that we established and the rate of water you need barrels per day, balance for minute to do the completion jobs that we want. You need a strong supply source. And then that really helps de-risk and sets us up to take advantage of that side of the events. And obviously pumping water is much more efficient to trucking as we've laid out on the slide. On the other side of the disposal end, it is sort of a tighter market on how an adequate disposable capacity, if fracs don't line up properly full bags and produced water volume. So whenever we look at our own business model and we set our plans, we talk 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 you balance which we've seen happen in a quarter or two when everybody has to disposal, it's get very costly, very quickly. So those the source side and the reuse side are big items that lead to call it margin producing opportunity going forward.

The next question comes from Biju Perincheril with Susquehanna. Please go ahead.

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 at 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. First on the hedge book, particularly 2020 and 2021 been able to take that revenue uncertainty off the table helps us obviously get more confidence 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 cost to basically turn in line a Utica well, we've also had some positive developments on that front in the last couple of months. On the drilling side we mentioned the drilling efficiencies particularly in the Southwest Pennsylvania area of the Utica. That's an important piece of the equation for rate of return. And with respect to the completion designs including Southwest PA Utica or 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 on 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 the 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 the activity set at the level now and let's assess see where the data come 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 long ago of data set for the Utica but also how compartmentalizedthe 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. Talk about the Geo hazards in some Southwest PA, the natural fracturing and how challenging that can be. And that is certainly been a factor in some of the two data points that we have with our wells. But when you look at Nick mentioned drilling efficiencies of the last four wells we've drilled in Southwest PA, all four wells have been drilled in that 30 to 40-day range with two wells one at 29 days and one in 31 days. So our drilling efficiencies have picked up tremendously. We gained a lot of knowledge on our completion design which is really helping us move towards that $12 million to $12.5 million 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 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 and 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. Order completion design, there wasn't seismic data being used. So you've got to take some of those over 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 from Marcellus and there are some areas that are more challenge than others. But we are - you 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.

If I think about the Incremental activity in Southwest PA, Utica, then would you say there is more a little bit more uncertainty or variably on the timing as you get the next batch of data points sort of proving up your thinking on the geology side?

The next few data points we get from our production standpoint, we’ve got to pads scheduled to turn in line in August and one in September. And so that production data will be significant and important. But as we continue to grow wells, as I mentioned in my comments, we have two rigs drilling Southwest PA Utica right now. We’ve drilled one 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 course and logs. But to build our confidence and build our - improves our understanding and really each data - each set piece of data helps us understand and reduce our risk.

And then the next question I had was on the three rigs you have at the end of will have still on contract at the end of year. What's the timing of when those three role 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 date but they are beyond that. But with anything we make those decisions. We're looking at the market and all the conditions that are hedging and price environment and our drilling efficiencies and we make those decisions and address that. We've got time frame set understanding when those rigs come up and we'll make sure those questions are answered and addressed in a proper time frame.

The next question comes from Jane Trotsenko with Stifel. Please go ahead.

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 docks in 2019 and 2020? Or if there are other factors that impact 2019 CapEx?

Sure. So there's different obviously different pieces of the buildup up to capital. And we've laid those out in the release in the slide deck. But certainly the incremental activity, the 14 tilts are big incremental piece of that and we try 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 20 activity now that we can get done in 2019. So if you're looking at things on a consolidated basis that's another driver. So those 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 that you add incremental activity in 2019 to kind of deliver higher production growth in 2020? What was the motivation by doing that?

Sure. This goes back again to the rate of returns driving our decision-making. So when we look at the incremental activity whether it’s the capital or the production that will come from the capital investment, we are ultimately looking at the rate of returns and a leading the rest of those metrics become more results versus what we are solving for, we are solving rate of returns. And the risk associated with those rate of returns. So when we look at our hedge book, particularly for 2020 and 2021 which will be a big determinant of revenue in the front two years of a shale well is going to be a big determinant of the alternative 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 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 and the Marcellus and then we talked through on some earlier questions about the confidence that we're growing with new 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 these together, basically the rate of return that we see coupled with the risk and the uncertainty tied to it put us in a position where we believe it's prudent to invest in that capital if for solving for intrinsic per share value.

I may ask the last question. I'm trying to understand the medium-term production outlook. So the 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 bend that you would like to stand within - you would stay within over the medium term, long term?

Yes. We will talk to 2.5 times leverage ceiling as the way we think about the balance sheet. We've also said, it is not just leverage ratio and isolation. We view our hedge is part and parcel 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 year two, one is our current trailing 12 months leverage ratio. But we like to look out one year, two year, three years, really we want several years of dependable, reliable cash generation from the business and we're setting our capital structure and we do look at 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 one, two years down the road, where most folks don't, if you don't have a hedge book to kind of predict the revenue side of your business.

This concludes our question-and-answer session. I would like to now turn the conference back over to Tyler Lewis for any closing remarks.

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.