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…

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…

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…

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.