CNX Resources Corporation (CNX) Q4 2018 Earnings Report, Transcript and Summary

Good morning. And welcome to the CNX Resources' Q4 2018 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [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. Please go ahead.

Thanks, Kerry, and good morning to everybody. Welcome to CNX's fourth 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; Andrea Passman, our Senior Vice President of E&P; and Chad Griffith, our Vice President of Marketing and President of CNX Midstream. Today, we'll be discussing our third quarter results, and we have posted an updated slide presentation to our Web site. To remind everyone, CNX consolidates its results, which includes 100% of the results from CNX, CNX Gathering LLC, and 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 a.m. Eastern today, which will require us to end our call no later than 10:50 a.m. The dial-in number for the 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 Don and then Andrea, and then we will open the call up for Q&A where Tim and Chad will participate as well. With that, let me turn the call over to you, Nick.

Thanks, Tyler. And I want to start with a couple of thoughts on 2018 results and then pivot over to some thoughts on '19 and beyond that. We could say that 2018 was yet another transformational year for CNX. But I believe that fall short and fully articulating with this past year is meant for the company. So let's just say that 2018 was the year where much of the foresight and preparation and the hard work, the steady execution of our team over the past number of years, they all gained real traction and allowed us to solidify our role as a leader and an innovator in the space. As highlighted in the executive summary on Slide 3 with the slide deck that we posted, I think the result speak for themselves. We grew EBITDAX per share by over 90% year-over-year as further confirmation of our cost structure, our programmatic hedge book and our capital rates of return. We built the robust balance sheet, finished below our targeted leverage ratio of 2.5 times. And we led the way in share repurchases for E&P industry, retiring almost $0.5 billion or more than 14% of our total shares outstanding since the inception of our program in October of '17. And as we look to the future, we got an even bigger opportunity to retire more shares; and clearly, the fourth quarter was a great end of great year; set us up nicely for all we hope to accomplish moving forward; another year of execution and that execution manifested itself in the results. Now, couple of thoughts about 2019 and beyond. First and the most important one, business model mission they remain unchanged. Slide 4 reconfirms our philosophy and the tactics that we employ. We're not solving for production growth or maintenance production, instead our strategy is simple. We look to maximize the intrinsic NAV per share of this company, and we're going to do that through prudent capital allocation. And it sound simple because it is simple but of course it takes the excessive focus of a talented team to make that happen. So we have and we’ll continue to operate this company to drive a long-term value for our shareholders. That fundamentally means four things and we have highlighted those in the pyramid that you see on Slide 5. So those four things looking at that pyramid. First one, we believe in the intrinsic per share value of the company. We monitor it and we measure it constantly. Second thing, this constant focus on intrinsic value per share, it's allowed us to confidently reduce our share count meaningfully at really deeply discounted prices. Moving forward, after first funding our business needs, we’re going to continue to methodically retire shares when we have extra balance sheet capacity and/or cash. And when the return is competitive then it provides an adequate margin of safety. So methodical, clinical that’s the name of the game when it comes to our share buyback program. Third thing, we are making discussions based on risk adjusted returns. We apply hurdle rates, margins of safety across all capital allocation decisions and that ensures not just a good hypothetical rate of return on paper but tangible value being created through our investment decisions. At assessment decision making, it's not done annually or quarterly, it's done weekly. As new data come in and as variables change, which inevitably do in this industry we reassess and adjust our capital allocation accordingly. And we don’t use 2019 strip pricing and then assume steady state prices that are higher than the current forward strip prices beyond that. Fourth and final thing, we have a solid minimum level of activity, which is largely hedged and that maintains the healthy company. We consciously setup the business so we don’t commit ourselves beyond that, and we’ve got the flexibility to do more if and when we deem it appropriate. Now another thought that I wanted to highlight is the pace of change with CNX when the tactics that I just mentioned come into play. I think Slide 6 does a good job of illustrating that. A 160 plus percent increase in EBITDAX per share in two years is impressive. But Slide 6 I think is a compelling data set, not only to show how our philosophy and tactics delivered results, but also what that means for potential when you look into 2019 and beyond. Finally, let me wrap on a theme that Don and Andrea are going to have more to say about in a couple of minutes. As we strive to be great capital allocators and recognize the importance of making decisions real time and fluidly versus annually or stack. That’s why we presented our minimum activity level in the release along with the CapEx and EBITDAX the results from it for 2019. Where we go from the minimum activity level? That's going to be a function of many variables. But the filters and the decision making criteria remain the same; maximizing NAV per share; assessing risk adjusted rate of returns; and comparing them to margins and safety. And activity beyond the minimum case, that comes down in large part to the Utica. CNX is a leader in the Utica horizon and we see the potential to allocate billions of dollars in capital into that horizon in the coming years. Now, that first mover is a great opportunity, but it also carries risk. And we've seen that with pioneers in shale fields like the Barnett, as well as frankly in our basin with the Marcellus. So we want to be judicious and astute in how we allocate capital in the Utica from the get go, because getting it right at the start that's tremendously higher an intrinsic value creation and getting it right halfway through or even further down the road, especially when you're the leader like we are with the Utica. What does it getting the right cover, cover is a gamut from being a responsible operator in HSE matters, our drilling and complete capital and capital efficiencies, infrastructure is a big piece of this, making sure that we've got the right size and time midstream and water infrastructure and also, of course, things are like our completion designs and ultimately our well profiles. All of those are drivers of rates of return and NAV. So again, more of that in a few minutes from Don and Andrea. In sum, 2018 all about execution for the CNX team we delivered much more to come in 2019. So with that, I’m going to hand it over to Don to get into more of the details.

Thanks, Nick, and good morning everyone. I would like to start with our quarterly results on slide seven. Consolidated adjusted net income for Q4 was $160 million and consolidated adjusted EBITDAX for the quarter was $314 million or $1.58 per outstanding share when using our share count as of January 18, 2019, which will tie to what we file in our Form 10-K. Slide eight further highlights some of our quarterly accomplishments, specifically to our average cost and margins. In the fourth quarter we had total production cash costs of $1 per Mcfe. This resulted in an average cash margin of $2.09 per Mcfe or a margin of 68%. When we use fully burdened all-in cash cost which include all cash items for interest, SG&A, other corporate expenses and other miscellaneous income and expense, we had an average fully loaded cash cost of $1.46 per Mcfe. This resulted in an average fully burdened cash margin of $1.63 per Mcfe or a fully burdened margin of 53%. These margins are substantial and underpin the confidence we have in our cash flows and our ability to generate risk adjusted returns on our capital program. Slide nine walks through another way to look at our go forward cost structure build up. This look uses our average Q4 production and fully burdened cash costs and adds when an approximate new capital cost per Mcfe would be for a new theoretical Marcellus well. This really gives you a look at what our completely all-in fully burdened with its associated capital charge for new unit of production, cost structure would look like on a go forward basis for a model Southwest PA Marcellus well. And it is worth noting that this is a stand-alone E&P cost view and doesn't take into account the net back or consolidated benefits we get through our MLP ownership on MLP gathered volumes. We strongly feel that in order to succeed in the commodity business your all-in cost stack, and this includes capital efficiency needs, to be best in class and we will focus on improving our strong position among our peers. Slide 10 should be a familiar slide by now. As you can see, we had a trailing 12-month net debt to attributable adjusted EBITDAX of 2.25 times at the end of the year and we bought back 6.8 million shares since November 1st of last year. Slide 11 really designs the true progress we have made in returning capital to our shareholders. As you can see from this slide, we're the only Appalachian E&P company to actually reduce our share count over the last five years. On the other hand our peers have increased their share count on average by approximately 50% since then. We have a strong track record of per share focus. Before I discuss our guidance, I want to spend a few minutes on slide 12, expanding on our thought and philosophy when it comes to our go forward business plan. As Nick mentioned, our overarching goal is to continuously improve the intrinsic value per share of the Company and because we are in a dynamic industry with constantly changing inputs, we feel having the right combination of certainty and flexibility is a must to provide through the cycle profitability and returns. This reality is why we constantly rework and maintain a minimum activity base plan. It covers our commitments including with CNXM, maintains a healthy company, generates a base level of capital returns, it's protected from material changes and gas prices through a strong hedge book and protects us from major cost swings and commitments through thoughtful service contract management. Having a low cost structure and a strong minimum base activity level plan, protected by a significant hedge book, is essential for long-term success and value creation. Now that this base minimum activity plan is in place for us, we are in a position to constantly work and evaluate incremental capital deployment. As Nick mentioned, this isn't an annual process. This is a disciplined, nimble, fluid process that's constantly being evaluated as relevant variables change. These decisions are heavily influenced by forward strip gas prices, changes in our operating data and metrics, new industry data, our share price, timing on when a decision needs to be made, our balance sheet and our current risk appetite, among other things. And to reiterate, all of our decision-making centers around constantly working to increase the intrinsic value per share of the Company. Slide 13 highlights our 2019 guidance for our base minimum activity level I just talked about. As you can see from the slide, it results in a D&C capital budget of approximately $575 million to $625 million, a production range of 495 million to 515 Bcfe and a non-D&C capital spend of approximately $175 million. As the year unfolds and any incremental capital decisions are made based on the inputs available to us at that time, we will update our guidance accordingly, including any updates to our production mix. The last piece of guidance I wanted to discuss is our EBITDAX guidance. And before I get into the numbers I'd like to introduce a slightly new methodology we are focused on moving forward. For reference, in each quarter throughout 2018, including the fourth quarter, we have shown results on both an attributable to CNX shareholders basis and on a consolidated basis, matching the way we provided guidance for 2018. Going forward we are moving away from attributable and instead replacing it with E&P stand-alone plus CNXM distributions. We think this metric is a more accurate depiction of the cash earnings available for use at CNX. For 2019, our range for this metric is $790 million to $825 million. However, as we have previously stated, most analysts continue to model CNX on consolidated numbers. So we will continue to show these going forward as well as seen on the slide. Slide 14 highlights the distribution profile from a ownership stake and CNX Midstream that we are using for the previously mentioned guidance. It also highlights how the value of CNX ownership and CNX Midstream continues to grow significantly year after year. Slide 15 highlights our updated hedge book. We continued our strategy of programmatically hedging both NYMEX basis to truly de-rick the Company's cash flows this past quarter. As you can see on the slide, we have built a strong position methodically over time that allows us to protect our capital returns from changes in commodity prices and ensures we are able to maintain a healthy company and balance sheet for years to come, even if gas prices become more stressed than the forward strip current recess. And if gas prices go up, our deep inventory position gives us the luxury of adding incremental activity as the risk and adjusted returns warranted. Ultimately, like we've said many times throughout this call, we are constantly assessing and making these incremental decisions with the goal of increasing the intrinsic value per share of the Company. With that I'll hand it over to Andrea to talk about our operations.

Thank you, Don, and good morning everyone. I'd like to start by highlighting our activity in the fourth quarter and for the full year of 2018 as shown on Slide 16. We turned in line 16 wells, which consisted of 11 Marcellus, one CPA Utica and four Ohio Utica wells. So for the full year of 2018, we drilled frac and TILs 78, 64 and 68 wells, respectively, while running three to four rigs and two frac crews throughout the year. Our 2018 program was not only back end weighted, but very much weighted to the fourth quarter. We had a lot of wells that we turned in line safely and compliantly late in the quarter to come screaming into the end of the year. Diving deeper into the fourth quarter, Slide 17 summarizes our solid operational results. A couple of important items to note. We finished the year at the high end of our production guidance range at 507 Bcfe for the full year of 2018. And when you look at the total production from our retained assets, which excludes the assets we divested last year, that 2018 production is 480 Bcfe. We saw tremendous cost improvements in the quarter and total production cash costs finished at $1 per Mcfe. The chart on the bottom of the slide highlights the significant and consistent cost improvements we've seen over the past two years. Some of it is driven by our production mix and in the quarter we saw Utica cash costs at a mere $0.42 per Mcfe. And it's the Utica program that started with our development in Monroe County, Ohio, which has been a big part of CNX's development over the past few years. And those dry gas volumes that have helped us significantly drive down costs. Lastly, E&P capital in the quarter was $266 million, driven by accelerating activity at the end of the year that sets us up for this year in 2019. Breaking it down further into cost by segment on slide 18, I'd like to highlight that our total production cash cost in the Marcellus for the quarter were $1.20 per Mcfe while the Utica as I mentioned was $0.42 per Mcfe. Even though Marcellus costs are down year-over-year, the production mix and specifically the wet dry mix plays a prominent role for this segment. The Utica doesn't have a mix issue because of course it's all dry gas, that's a lower gathering rate than the Marcellus. Lastly, I'd like to mention that even though our CBM segment doesn't get a lot of airtime, it continues to produce some noteworthy results year-over-year as costs are down almost $0.30 per Mcfe or nearly 20%. We continue to drive efficiencies in this area. The performance of the team can be seen in all areas of the Company, but one area that we believe has gotten somewhat overlooked externally has been our Marcellus performance. The industry of course is excited about the Utica and we're excited to be the play maker. For the time being though the Marcellus is our bread and butter and continues to improve year-over-year with 2018 being no exception. Slide 19 nicely illustrates the performance we're seeing in the Marcellus relative to a couple of our dry gas peers, with CNX having the best performing Marcellus wells in the industry as demonstrated by our 2018 production. The same techniques for earth modeling, reservoir and completions modeling and data analytics that we've used in the Utica, we've also applied to the Marcellus. The Marcellus has been and will continue to be a significant part of our development plans. When we look back across all the Marcellus wells, you can see it from the slides that Greene County our EURs are outperforming our peers by up to 14% and with some of our best wells performing at 3.5 Bcf per thousand foot. This performance is driven by our highly targeted geosteering with 94% of all Marcellus lateral steered within a 12 foot target zone, optimized completion designs, optimized lateral spacing far less than a thousand feet, managed pressure draw down and a two pipe midstream system that allows us to maximize pressures from new wells without knocking off old wells. In the third quarter we highlighted the performance of our Richhill and Morris fields with 77% and 20% increases in EURs, respectively, from legacy wells to their current type curve. This is why we continue to allocate capital to the high rates of return in the Marcellus and lock in those returns with our hedge program. Now let's shift our focus to the Utica. It's our methodical and steady engineering and analysis that's been driving us up the learning curve since we drilled our first deep dry Utica well, Laggard in 2014. Now let's update you on the Shaw pad that we recently started fracking in Westmoreland County. Recall that last year we drilled four deep dry Utica wells on the Shaw pad which is located in our CPA operating area. During frac operations earlier this week on the Shaw 1G Utica well, we experienced a pressure anomaly while pumping. All frac operations on that pad are temporarily suspended and we are currently evaluating the cause. That being said, the reservoir pressure is consistent with other CPA wells including the latest Q4 TIL Utica well just north of the Shaw, the Bell Point 6. As you can see on slide 20, we're ecstatic that the Bell Point 6 is performing in line with our 3.5 Bcf per thousand foot type curve and has been holding steady at 21 million cubic feet a day since October, which is bigger than any well that I ever saw when I worked offshore in the Gulf of Mexico. So you can see that even with the factory development of our low-risk, high return Marcellus why we continue to be excited for the deep dry Utica with our most recent Bell Point 6 results. As Nick mentioned, we're working judiciously to make sure we get the Utica right out of the gate. We've seen too many other playmakers rush into decisions about wells spacing that is too wide or too tight, trial and error completion methodologies and undersized midstream build outs that leave billions of dollars of NAV on the table or in this case in the ground. When you're allocating billions of capital dollars over years, it's important to employ data to drive those decisions to generate the greatest NAV. We're looking to other basins where I and the team have worked like the Permian and Eagle Ford to get it right. With our electric frac crew from evolution arriving in the spring, simultaneous operations, remote frac operations, new casing designs and real-time predicted geosteering we have a step change and efficient operating cadence. And combined with fiber micro seismic subsurface DNA and continued modeling for optimization, we're further driving down costs and driving up production. We're also driving improvements through our new integrated real-time operations center here at our headquarters. We can automatically control many of our pads including automatically shutting in, ramping chokes, blowing wells down and automating our managed pressure drawdown procedures thus dramatically reducing our downtime. On top of that, CNX is taking greater control of our critical resources like sand and water. In the past we would rely on our service providers to source the sand that is a critical component to our operations. Starting this year we're sourcing our own sand which has de-risked production delays due to lack of specific sand availability and lowered our frac costs by over $10 million for this year. To pump sand, of course we need water which continues to be a critical resource to feed the high demand of our frac fleet. Even today when we are often seeing 13 stages per day and with our highly efficient evolution crew on the way, this is very necessary. The Ohio River waterline build-out will supply our SWPA operations while reducing water costs by 80% which is highlighted on slide 21. This waterline is core to our SWPA development and expected to be in service in the fourth quarter in 2019. Finally, we can't execute our Marcellus and Utica program without an integrated and optimized midstream business. We talked about how we're designing some of the midstream systems at our March 2018 Investor and Analyst Meeting. Some of this showcased the two pipe system with a low pressure and high pressure line. This build-out is helping us to support our stacked pay development. So when you have an industry-leading core of the core Marcellus position coupled with a multi-billion dollar NAV opportunity in the Utica, you have a lot of optionality where you can make real-time data-driven development decisions. And as Don pointed out, with the ultimate mix for 2019 looks like it's fluid as we'll continuously evaluate our results and adjust throughout the year while we operate safely and compliantly. We we will stay the course in 2019, maximizing NAV per share, assessing risk adjusted rate of returns and comparing them to margins of safety. With that, I'll turn it back to Tyler.

Thanks, Andrea. Operator, you can open the line up for Q&A at this time please.

We will now begin the question-and-answer session. [Operator Instructions] The first question will come from Welles Fitzpatrick of SunTrust. Please go ahead.

If we could jump to Slide 13, you put in a lot of factors that might shift around CapEx, maybe I'm thinking about it wrong, but in my mind dropdown is always kind of one of the biggest factors. Is there a reason that's not noted as a potential catalyst for an acceleration or are those thought of as just your mark for to feel the buyback?

Yes, so this is Don, so as we've just discussed and talked and laid out a lot of detail back in our Analyst Day, there's a lot of optionality when it comes to that. Right now both base plans for CNX Resources and CNX Midstream just assume those don't happen. So anything in that arena would just purely be additive to the things that we're doing both at CNX and CNX Midstream. So, no color or guidance outside of just showcasing what these assets were back in Analyst Day.

And then I understand that it's hard to put any numbers on it. But in general the slower drilling cadence, should we assume that will slow the drop down cadence or do you see those two as somewhat unrelated?

Yes. So we never have given a drop down cadence, so how these will go and how they unfold on, as we've said we look for ways that really help out both upstream and midstream when we do these types of transactions. So obviously our drilling cadence as well as many other factors really affect how you would do those and when you would do those. So, no baseline guidance to go off of and really we just are going to constantly look at what's in the best interests for both sets of shareholders.

The next question will come from Holly Stewart of Scotia Howard Weil. Please go ahead.

First on the -- understanding this is kind of the minimal level of activity and you can be nimble. But how does this current plan in place compare to like the four rigs that you have running and the three frac crews that you outlined and -- that were there on 4Q18?

So, Holly, I think when we look at the beginning of the year we still have the 2018 capital that was setting us up for this year in terms of that activity that was in there. So, as Don mentioned, we're going to look at the program throughout the year and flex those rigs and frac crews as necessary. Definitely evolution is locked in for the year and the capital efficiency that we expect out of that crew should definitely help us do whatever we need to do to flex it up and down.

Understood, but the $600 million that's outlined today, is that four rigs and three crews?

I think it will depend on where we want to put that capital throughout the year and depending on which assets we want to put that in, that's going to change that dynamic because of different operating metrics in Utica and Marcellus.

Then maybe just a try then on the cost side. You didn't outline cost guidance, but just assuming this minimal level of activity is the run rate that we've seen in the last quarter of the year or even the average for 2018, is that a good -- just thinking of LOE or GP&T, is that a good run rate to use in '19?

So as we're sorting through this, a couple of pieces I think that could be helpful on that, Holly, is we've kind of outlined our cost by segment. As we've talked, the average production cost is a big factor on how much production comes from each segment. We've kind of hit on this minimum activity level being heavily Marcellus-weighted. So, I think that kind of help see how the cost should unfold over through '19. Now as we've talked and as Andrea said is -- is we're making these decisions on how the full mix unfolds that could potentially change, but right now I think you can expect segment cost to be similar and it's just how the mix ends up unfolding over the course of the year. But right now with the Marcellus heavy, you'll have some more Marcellus cost in the mix.

And then it looks like you added a lot to the 2020 hedge book. It may probably making you of the most hedge in the Appalachian group for 2020? Can you just maybe, Nick, give us some general thoughts around that process?

It goes back to the focus on risk adjusted rate of returns and the profile of a lot of the capital that we're deploying now over the next 2 to 2.5 years, that's going to be the biggest determinant on the rate of return, whether it comes from the roost or not. So different views on gas prices and most of us tend to be bullish on gas prices, but in the end we know that the best set of data are the forwards. We basically allocate capital off of that. And then the one advantage of E&P, despite its volatility of natural gas you can sell your production that you're going to produce in the future forward. So we want to take advantage of that. So to me it goes back to the risk adjusted rate of returns and using the forwards as the reality at this point in time and wanting to make sure that we lock in those rate returns or at least take one of the major risk factors off the table.

And just to add that a little bit -- if you're looking at potential incremental activity, you want a nice strong foundation underneath you. So as we move forward, having our minimum plan really solid, strong and put to bed allows us to really take advantage of incremental opportunities as we see them.

The next question will come from Joe Allman of Baird. Please go ahead.

Just a couple of quick ones from me. So one, Nick and Don, there's no big change in gas prices over the past seven months. And I cite seven months because seven months ago you gave some guidance -- your latest guidance for 2019. So what data are you seeing that makes a slow down? And if you kind of approach it first from a kind of macro-economic level and then from kind of a basin level and then from kind of a micro level which means kind of at the well level or takeaway level, so what data are you seeing that makes a slow down and what risks are you concerned about to make a slow down? And then just a follow-up. All else being equal, slowing down makes sure NAV go down. And so if you could address that as well.

So the way we've structured this and the way we're thinking about and talking through it is, we wanted to clearly articulate our minimum base activity level. A lot of these incremental capital decisions are really to be made on back half of the year, middle half of the year, so they're not front of our nose, on left-right decisions. So as the variables change over the course of these decision-making milestones over the course of the year or not change, we will be allocating left-right accordingly. So, nothing changing on thoughts and philosophy, just trying to be thoughtful on articulating the '19 piece and having it unfold over time since -- especially since a lot of capital spent in the back half of '19 doesn't really do anything for '19 production. So we're just trying to be thoughtful in how we're thinking about things, just incremental one step at a time as the year unfolds. It's hard to put our business in a calendar year box.

And then, Joe, just a couple -- two other thoughts to add to Don's. One, and he hit on this, right, it's a minimum activity set, right? So as we decide what we layer in or incrementally change off of that minimum set, we'll see as the year goes on to Don's point, but two, you're right obviously about the pace and activity versus NAV per share impacts. And again we look at that constantly. So, the whole set of variables that drive NAV per share which are many and whether we're looking at the next dollar allocate into the asset base or retire share with or wherever the opportunity might be, we're constantly looking at those ranges of rates of returns and how activity pace and a whole bunch of other factors will change NAV per share.

So if I hear you guys correctly, so you're saying that -- so there's no change in your macroeconomic viewpoint, no change in thoughts about the basin, no change about the well productivity, well performance, well inventory or no change about takeaways -- the takeaway situation. Is that fair?

Yes, so we're always looking at the data out there. I mean the strip's obviously a good indicator as many as, you know, we follow these things close as anybody. And really it's hard to accurately predict the future. So what we're doing instead is making sure we have a strong minimum activity set that's locked in and loaded that can carry us through and as we're coming up the milestones, on new decisions to be made, we run the new information that changes or doesn't change through the model and decide as we go on those.

And you guys have always been thoughtful and deliberate and you were certainly thoughts and deliberate throughout 2018. And so clearly there's a different approach to guiding. Can you just talk about like what is it -- what does it that makes you think differently about guiding now versus you know at any point or in 2018?

I think, Joe, there are a couple of things. One, we talked about this in the commentary. We are on the cusp of making some major decisions with respect to the Utica program and 2019 is going to be a pretty rich dataset of everything from well results to further well histories with some of our CPA and Greene County wells that have been online looking at confirming type curves which Andrea had hit upon. So all those factors in terms of how they not just impact our D&C capital but also what that means for infrastructure build-out and timing of such, we see a big opportunity there to getting it right at the start versus getting it right down the road when it comes to the NAV per share. So we want to basically leave our options on the table with respect to that incremental activity. And then as the year unfolds and our data set expands, we come out with up-to-date or mark-to-market so to speak to you on what the incremental activity might be.

That's helpful. And just the last one. Production cadence for 2019, is it -- what does that look like as we move through the four quarters especially given the kind of pressure issue that Andrea talked about?

We're not saying what that's going to be especially since we might be planning on flexing some of that throughout the year. So we'll keep you posted.

The next question will come from Sameer Panjwani of Tudor, Pickering, Holt. Please go ahead.

So based on early feedback from our conversations it seems like the market is pretty concerned about a degradation in capital efficiency based on your 2019 guidance. And as you can imagine investors are pretty wary of this given recent issues highlighted by one of your peers. So with that context, can you provide some color on what's driving the implied production decline on an exit-to-exit basis while outspending cash flow? And along with that, looking for a year-end '18 base decline and maintenance CapEx estimate?

So again a lot of these things it's hard to box things in the hard calendar years as these production profiles and capital allocation decisions, as you know, it matters where it's beginning of the year, at the end of the year. So a lot of this as we think through its context over several years that it's kind of more helpful in understanding this. Where we sit today and how we're allocating and showing our guidance, we're kind of showing the definite amount we're going to do in '19. Obviously what we do in '19 has factored in years other than just '19. But as we're setting it up now, this is kind of a '19 view of what to expect from us at the minimum level.

So I guess to clarify, it kind of seems like what you're saying is that there's a healthy amount of CapEx that is going to impact production more in 2020 and there could be more of a back end weighted program in 2019. Is that a fair assessment?

Yeah, I think in any year, I mean, I think it's, you know, TILs, they don't turn on line till the end of the year or the drilling and completions, they don't turn on line until January, don't really affect '19. So, there's -- it's hard to fit these big wells in the calendar year bucket. So I guess without completely going into specific details, end of the year TILs and don't do a lot for '19.

And then from a higher level standpoint, how do you think about line of sight to organic upstream free cash flow and the roll off of the heavy non-D&C spending that we're seeing this year over time?

So two things there, as Nick mentioned in his earlier remarks, we're not solvent for free cash flow, we've solvent for per share intrinsic value creation. So how that unfolds will be a byproduct of how we're running the business based on our intrinsic value per share focus. I think when you look at the non-D&C spend, Andrea highlighted that a large waterline that we're building for southwest Pennsylvania. As you can imagine, that'll take care of our southwest Pennsylvania needs for time to come. Up and other areas that we operate CPA in particular, there isn't any need for something like that. I think that can help you think through the need for non-D&C going forward.

The next question will come from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.

On Slide 8 you called out low transportation gathering and compression costs as a CNX advantage versus peers. I'm just wondering how durable are those advantages going forward?

Jeff, thanks for the question, this is Chad. You know a lot of those cost advantages really come from our dry-wet blend. The vast majority of our Marcellus production is dry. And so it does not need to be burdened with processing costs. You know, at a high level processing costs can run anywhere from $0.50 to $0.70 depending upon what that barrel looks like and who your processing counterparty is. So by having more dry gas than wet gas, we're able to [indiscernible] incremental expense. And as the blend moves into Utica, it's even a much better cost structure, so it's cheaper gallon rate at the CNXM level and -- because it's dried also, avoids all that processing expense.

And I think the other piece is that are an advantage that we think is sustainable here are on a few fronts, one, our blending strategy. So, Chad walked through process and cost, a big piece of that too is not force the process, low BTU gas, that doesn't have the advantage of covering its processing costs for the liquid sales. So we stay very nimble in there with our wet-dry blending strategies in that damp area and Southwest PA. Another part is just a stack pay in our concentration of our core areas. It allows us to be much more capital efficient with the midstream builds and with the stack pays being able to reuse pipes twice we're able to have a much more efficient midstream system. Some of the two pipe systems Andrea talked about really helps on your compressor and how you're thinking about managing pressures of the field across it. And then lastly we haven't really hit in this guess Analysts call presentation, but our FTE book is very different book than most. We've stayed at very FTE-light. I think everybody is aware, a lot of these new FTE projects come with a pretty heavy cost and that cost actually doesn't cover the -- I mean you don't get an uplift from the price you sell the gas at the end of the pipe versus the cost it takes you to get there. So that's obviously an advantage that we feel we will have for decades to come if this FTE contracts are kind of high in price and long term in nature. So those things we feel can keep us at the industry-leading position.

Thank you for that comprehensive answer. And my other question, you've talked a lot today in various terms about a number of Utica variables that are going to be important to your future development. Your well results demonstrate completions competencies are already high. So I'm just wondering what other D&C variables do you see as most critical and solve before really going forward?

When we talk about the Utica, one of the things that we've been very clear about is that it is not a blanket play and it is different region by region. And so, as Nick mentioned, when you're a play maker, really ensuring that you have the variables understood out of the gate and that you're gathering that data and effectively analyzing it before you make those critical capital deployment decisions is key and that is an area by area basis. So when we talk about our designs for a CPA versus our designs down in Southwest PA region, those are two very different looking things, not only because of the geology in each of those areas but also because of depth and pressure and really rock type as well. So you know when we're looking at how do we optimize early on, when you think about these areas each pad is like a mini factory. And when you're putting $60 million to $100 million into a pad and then you have operations on that pad for a year, ensuring that you're getting your lateral spacing correct, your stage spacing correct, your stage volumes to ensure that you're maximizing recovery factors, what you're managed pressure drawdown protocol looks like, to ensure that we can maximize EURs at the wells, all of that has to be designed out of the gate with the right data to ensure that you understand that. So once again as we said earlier, we're not leaving NAV value in the ground that we can't go back later on. You can't fix a parent-child relationship after you've drilled the well.

Okay, that's very helpful and if I could just follow up real quickly. You also mentioned that you're studying or using your experience in other basins like the Eagle Ford and the Permian to help this effort. Could you just give some quick color as to how those would correlate to your future Utica involvement?

Yes. So when we talk about stacks pay development, certainly Appalachia is not the first basin to head down this path. Having worked in the Niobrara, having worked in the Permian, there are a number of operators that got it right and there are a number of operators that got it wrong. And when we talk about getting it right, it's about the slow methodical analysis of your data and information and ensuring that you understand that. And also secondarily, really what we've seen in the unconventional space is that applying technology is one of those key step changes that can really drive forward efficiency and NAV. So when we talk about the technology piece about evolution which we saw them operating down in the Eagle Ford and we loved what we saw in terms of efficiencies, similar pressures and depths that we see down there that we can apply here. When we talk about chief development with other operators in the Permian and simultaneous operations, those are areas that we're looking at, casing designs that we're seeing in basins that have the depths and pressures that are similar to what we're seeing in the Utica. We're applying that as well. And then overall what we've always said is we're a heavy modeling and data analytics organization here at CNX. And that's really driving our understanding of making sure that we know what's happening in the reservoir that we know what's happening even from the infrastructure and how all of that plays. And it's not just a well-by-well view, it's a systemwide view to understand what that looks like for full term development.

The next question will come from Kevin MacCurdy of Heikkinen. Please go ahead.

Maybe to follow up on the last question, can you provide an update on drilling days and cost for the latest CPA Utica wells?

So we've been seeing the latest deep drilling Utica well -- they're drilling on the deep Utica wells, really coming in on the target that we've put out there. So we're seeing $14 million out there, we're zeroing in still on that $12.5 million well. Bell Point 6 which was a 7,000 foot lateral came in at about $17.5 million. Keep in mind that well is a single well on a single pad versus the multi well pads that we have out there in the future. So -- and then frac efficiencies are still coming down and improving on that as well and starting to get closer in line with what we're seeing on the Marcellus side.

And given the status of the Shaw pad, does this base guidance include any deep Utica activity in 2019?

Yes, we're still planning on going forward with our deep dry Utica program and it doesn't have any impact on our long term view or plans for the Utica. So we're going to stay the course.

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

Okay. Thanks, Carrie, and thank you everyone for joining us this quarter.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines. Have a great day.