CNX Resources Corporation (CNX) Q2 2019 Earnings Report, Transcript and Summary

Good morning and welcome to the CNX Resources Second Quarter 2019 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.

Thank you, and good morning to everybody. Welcome to CNX's second quarter conference call. Today, we'll be discussing our second 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 and CNX Midstream Partners LLP. Earlier this morning, CNX Midstream Partners, ticker CNXM, issued a separate press release and as a reminder, they will have an earnings call at 11:00 A.M Eastern today, which will require us to end our call no later than 10:50 A.M. The dial-in number for 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 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.

Good morning, everybody. Tim is going to go into some of the operational details from the quarter in a minute, many of which we're excited about, and Don's going to discuss the financial details as usual, which is going to include our updated 2019, as well as our 2020 guidance. But before I turn it over to those two, I'd like to focus a couple of brief remarks on how CNX is different and why this is important, especially given the challenging commodity price environment that we're all dealing with out there. And I'm going to start on slide 3, which helps, I think, highlight three main drivers of differentiation for CNX relative to the peer group. First one, maybe the most important in some ways is our marketing strategy, which includes our hedge book and it also includes our minimal firm transportation strategy. FT, in some ways at least as I look at it, is more debt like than debt itself. So, we seriously contemplate any commitments that can have unforeseeable at the time and major negative consequences into the future. Second big differentiator is our cost structure and this is, of course, a commodity business. And that cost structure is also supported by our blending strategy, which we believe is going to result in strong cash margins. And then the last or third differentiator is the asset portfolio. That includes the approximately 100,000 core Southwest PA Marcellus acres that includes over the one million total acres of our footprint, the large stacked pay inventory, it includes our Midstream control, and finally, it also includes a robust water system that's going to benefit us for years to come. Now, these advantages, they've helped us execute a consistent strategy and a philosophy, which is built around generating risk adjusted returns to grow our NAV per share, while at the same time we're making sure that we retain a healthy balance sheet. We follow the math in everything we do. And if you take a look at slide number 4, our 2019 and 2020 program, which we will talk about shortly, it drive several capital allocation opportunities. We often get the questions on whether we can grow EBITDAX or whether we can reduce leverage, or whether we can reduce share count. For us, however, we don't view these opportunities in isolation, and I think the results speak for themselves. Because of our attention to generate risk adjusted returns, we've been successful in growing EBITDAX and reducing leverage and in reducing our shares outstanding, and we expect more of the same when we look into the future. And when you're solving for optimizing intrinsic value on a per share basis, this becomes a really powerful dynamic in any part of the commodity cycle, including this one as well. Now I just mentioned and speaking of that focus on per share metrics and a per share basis, I just want to spend a minute on slide number five. The best long-term illustration of our philosophy is that we refuse to issue equity during the past five years unlike all of the Appalachian peers. And we've also reduced share count by 19% since the start of our buyback program. Now these two things together, they duly over the past half decade, I think are testament to the value that we place on growing the company's NAV per share and ultimately working to protect the equity for our shareholders. And we think that the value we place on capital allocation and ultimately the denominator is a significant differentiator compared to the peers, and you can see it. CNX reduced again, our shares outstanding by 19% over the past year-and-a-half, whereas, peers on average increased share count by over 50% over the past five years, resulting in all of them having higher outstanding shares since then, as of the end of the second quarter. Let's jump over now to slide 6. This slide, I think, really illustrates the value of our Midstream company, CNX Midstream. We've shown a similar slide in the past, but we think it's important to highlight this company and what it means to CNX. To start, CNX Midstream is reaching an inflection point and is entering the next phase of its lifecycle. CNXM has been focused on a large capital build-out in 2019 and the end of that is rapidly approaching. So what does that mean? It means that CNX Midstream will start to generate free cash flow starting in the first quarter of 2020, and we think they can generate between a $120 million to $140 million of free cash flow next year. This provides optionality for CNX Midstream and subsequently CNX. Now what shape that takes ultimately is to be determined, we're working on it, but having options, that's obviously a good thing. Turning to the value of CNX Midstream, we think there's two main pieces of value to CNX, which are of course first, the 21.7 million LP units that CNX owns. And then second, the general partner value, which in the example on the slide, is shown at over $800 million, which brings the total value to just over $1.1 billion. We think that the GP value is often overlooked, despite CNX's expected receipt of roughly $75 million, give or take, from our distribution rights in 2020. Slide 7. This slide highlights some additional areas where we believe CNX is differentiated versus our peers. For 2020 in particular, we're one of the most hedged producers with 86% of our gas volumes hedged, including NYMEX hedges at $2.94 an Mcf. Our basis hedges, they also ensure that we're fully protected, unlike peers on hedges of smaller volumes. And our hedge program, when you couple that with our industry-leading costs, it helps drive risk-adjusted returns and our ability to generate free cash flow at the current strip price environment. And just to be clear and just to make that point when I say current share price environment, that's NYMEX around $2.55 a million Btu in 2020. So, if you believe gas prices are going to be higher, then obviously, we would expect to generate even more free cash flow. Ultimately, we think that some of these advantages are going to become more apparent as the industry tries to navigate once a weaker commodity price environment looking out into the future. Now we have a number of metrics listed on that slide that we think are important individually and CNX ticks every one of those boxes. We think these peer-leading advantages are going to become more impactful over time. And over time and moving forward, our focus remains on operational execution, and frankly, controlling the elements that are within our control. We've built a solid plan for 2020. It takes into account the challenging macro, this plan and the guidance that Don is going to discuss shortly. They illustrate many of the capital efficiency and cost improvements that we've realized over the past couple of years. But despite those successes, I want to emphasize that we are going to continue to strive for more and our expectation is we're going to accrue more of those efficiencies, which brings me really full circle in conclusion with taking a step back and just looking over how far we've come and where we're heading. Mid-2019 indeed, it has a sitting at an inflection point. And I think sometimes that gets lost with all the noise around commodity price and capital markets upheaval that's out there. But think about the confluence of developments and how they culminate in a very strong position for CNX. So think about, how we programmatically hedge to lock in returns and use the forward price deck to run IRR math when it was popular to do the opposite and use imaginary higher price decks. Our approach went from an unpopular one to a winning one, when you look at the price curve today. Think about how we didn't want to amp up our risk, by taking on the massive FT debt commitments and chase basis differentials that might evaporate the moment a new pipe was commissioned. That helped create a strong balance sheet that we enjoy today. Think about how we invested precious capital in the water and Midstream infrastructure to lower our costs and capital intensity, not just further, but for longer. That build-out is nearly completed, which now benefits us by widening our protective moat of low-cost and high margin, also yielding lower capital spend in these non-D&C areas moving forward. And think about how we paid as much attention to the denominator, when optimizing intrinsic value per shares as we do the numerator. That's how we were able to retire 19% of our Company at discount prices to our internal NAV per share view, and we now enjoy a year-on-year per share growth and EBITDAX, and more importantly, NAV itself. And then finally, think about how we invested in technology through electric frac spreads and real-time operating control rooms. Being first movers and best-in-breed in these areas, that compressed cycle times and capital intensity. That in turn, puts us in a position to generate free cash flow in 2020, while significantly growing production. So for sure, these times are challenging. When you look at the price deck, but our philosophy of optimizing NAV per share, our focus on capital allocation and our tactical moves that I just walked through, they culminate in a company that's built to thrive in times just like these. Okay Tim, let's discuss our operations.

All right. Thanks Nick. Turning to the operational highlights for the quarter on slide 9. Production was 134.5 Bcfe for an increase of 1% over the prior quarter. We turned four wells in line in the second quarter, all in Southwest PA Marcellus, while we drilled 30 wells and completed nine. The quarter benefited from continued strong production out of our first quarter turn-in-lines also in Southwest PA Marcellus, helping to drive the 43% increase in Marcellus volumes compared to last year. E&P stand-alone capital expenditures declined 5% year-over-year to $226 million. Production cash costs increased $0.07 over the first quarter due to higher gathering, transportation and processing costs as expected. On slide 10, you can see that CNX stand-alone E&P has the second lowest cash production costs in the basin over the past four quarters at $10.9 per Mcfe. On a consolidated basis, which nets out payments to the Midstream MLP, production cash costs are just $0.78 per Mcfe. It's important to note that CNX is the second smallest producer in terms of average daily volumes and that we would expect unit costs to benefit from both increased scale and greater mix of Utica volumes, which had cash cost of just $0.47 per Mcfe in the second quarter. If commodity prices look to remain softer for the foreseeable future, we expect this cost advantage in conjunction with the hedge booked to become even more important. The hedge book which Nick discussed plays into our minimal FT strategy illustrated on slide 11. We predominantly employ a NYMEX hedge coupled with the basis hedge to lock in realizations rather than expensive long-term FT, which is effectively debt. On this slide you can see how we have -- we now have a fraction of the commitments our peers have, and perhaps most importantly, many of these large commitments are not generating a margin to justify their costs, despite being take-or-pay contracts. Let's shift to some of the recent developments in data giving us confidence in the program we've laid out. We've got a lot of questions on the Utica, specifically on getting costs lower. Slide 12 highlights some of the new data that we received this quarter on the four-well Majorsville 6, Southwest PA Utica pad which as you can see has beat our CapEx targets with an average of about $12 million per well on an approximately 6,500-foot average lateral length. We're very proud of these results. More importantly, we believe that this is repeatable based on the drilling performance and completion cycle times we achieved. Slide 13 highlights the blending strategy that we're employing. We have several damp gas pads being blended with dry gas and entering dry gas systems and bypassing expensive processing. With the coming turn in line of three Southwest PA Utica pads over the next few quarters, we expect to see a growing impact in the near term. And as a reminder, it only takes one Utica well to blend three to four damp Marcellus wells. On slide 14 is an example of how the Southwest PA Marcellus program continues to fire on all cylinders with our Richhill 71 pad, where we set a Pennsylvania state record by joining the longest lateral at 19,609 feet with the six-well pad having an average lateral length of nearly 16,000 feet. That brings our estimated D&C capital expenditures on the pad roughly to $800 per foot. While we don't expect laterals to consistently be in the 20,000-foot range, we will take advantage when the formation in geography dictate. Now turning to the slide 15, we have some details on our new integrated real-time operation center or IRTOC. IRTOC is the brand of our organization where various functional teams collaborate on everything from geosteering wells, to monitoring production and maintenance, to marketing gas. So just to sum it up, we're excited to be putting into action all the initiatives we've been talking about over the past few years and look forward to updating you on their outcomes over the next several quarters. With that, I'll hand it over to Don.

Thanks, Tim and good morning everyone. I will start on slide 16 with some of the financials results for the quarter. Consolidated adjusted EBITDAX for the quarter was $222 million, or $1.18 per outstanding share. And standalone EBITDAX plus distributions in the second quarter was $175 million, or $0.93 per outstanding share. As you can see, we were able to grow EBITDAX per share year-over-year, despite substantially weaker gas prices this quarter versus last. On slide 17, you can see our EBITDAX per share growth going back to beginning of 2017. And also in the quarter we bought back 8.8 million shares. Slide 20 shows our guidance. We are currently on track with our capital program for the year and are still expecting our 2019 capital to come in the previously announced annual range with the second quarter coming in as planned. For the remainder of the year, capital will peak in the third quarter and come off meaningfully in the fourth. We are forecasting annual production under this plan to be improved. And as such, we are raising our 2019 guidance to an improved range of 510 Bcfe to 530 Bcfe, a 15 Bcfe midpoint-to-midpoint increase with the same capital spend. As for EBITDAX, we have seen gas prices and liquids prices come down since last quarter's update. And as a result forecast to 2019 EBITDAX is lower despite the higher volumes. It's important to note that our updated EBITDAX guidance assumes strip pricing as of July 8. And as we have said many times now, we make our decisions and model our disclosures using the forward strip at the time. For 2020, we're reducing of annual capital expenditures by over 30%. And our production volumes are still expected to grow at roughly 10% based on the midpoint of our 570 Bcfe to 595 Bcfe range for 2020. This guidance highlights our capital efficiency. And for reference, the guidance is 10% below Street expectations on capital and 5% higher on production based on the midpoint of the ranges. Our 2020 development plan assumes that we'll return in line approximately 50 wells, which includes approximately a dozen Utica wells. Also, on a consolidated basis CMX Midstream's capital was down substantially following the large capital build-out completed this year. Lastly, based on the 2020 development plan, we expect 2021 production to be generally flat year-over-year, while allowing us to generate free cash flow at current forward strip prices. Slide 21 highlights sensitivities to different commodity prices for next year. And as you can see, we expect to grow production and generate significant protected free cash flow in 2020, based on the current strip pricing. The slide shows even with a further drop in prices, we will still generate significant free cash flow in 2020. We also tried to generally show the impressive free cash flow generation -- generating potential of our Company at a $2.85 NYMEX type pricing going forward. So to summarize, we are very protected from a near-term, low-commodity cycle and we have the cost structure and assets to produce significant free cash flow and a normal or high gas price environment. Slide 22 is an update of our production cadence. As you can see on the slide, we expect a decline in volumes in the third quarter of 2019, followed by an increase in the fourth quarter. In 2020, we expect consistent quarterly volume growth throughout the year by turning in line approximately 12 wells each quarter. The right-hand side of the chart is important. As we have touched on many times, CNX has differentiated itself with a top-tier hedge book. For 2020, we currently have approximately 86% of our volumes hedged based on the midpoint. And this hedge book is a competitive advantage for us and allows us the ability to ensure we generate returns on the capital we are spending this year, and it gives us confidence in our future cash flows and capital structure going forward. Slide 23 is just a reminder that we expect to receive an additional $110 million in tax refunds by the end of 2019 and expect to receive an additional $51 million in both 2020 and 2021. Slide 24 provides some of the revenue and cost line items as it relates to our updated guidance. In 2020, we expect total production cash cost to improve, mainly driven by transportation, gathering and compression. However, in addition to this, on slide 25, you can see that we have several processes under way to help drive all of our costs lower. We expect these efforts to positively enhance our spend and we will update guidance as they unfold. These items are consistently being worked on and improved on by our teams. The main drivers on these efforts will be combining certain teams across upstream and midstream, capturing efficiencies through our Integrated Real-Time Operations Center, having more efficient capital operations, and active contractor management, to name just a few. These efforts reflect our commitment to reduce costs in this low-priced environment and generally follow our commitment for continuous improvement in any pricing environment. Technology efficiencies and our desire to be a flat, nimble organization, will allow us to further lower our cost, which will widen our protective moat in a downturn and increase our execution in an upturn. With that, I'm going to hand it back over to Tim.

All right. I wanted to make one last comment and that is to say thanks to the Board, to Nick, and of course, all of our employees. It's been a great run since I arrived back here in Pittsburgh in January 2014, when we had really just begun our transformation from a large multi-segment conglomerate to a best-in-class, pure play natural gas E&P. That transformation is complete and we've achieved much in the last five-and-a-half years, positioning this Company as one of the strongest, lowest-cost operators in the basin. With that, I felt today was the appropriate time to announce that I'll be retiring from CNX at the end of the year, and that Chad Griffith will be taking over as COO. Chad is the logical choice to succeed me, having been president of CNX Midstream since September of 2018, overseeing all aspects of our Midstream business during that time. I wanted to make this announcement today, so that we have appropriate time to ensure a smooth transition. I intend to stay on board for the remainder of the year and do everything I can to help Chad as he transitions into this new role, overseeing both upstream and midstream operations. I have every confidence that Chad is the right person to take CNX into the future, and I look forward to working with him over the next few months to help make that happen. With that, I'll turn it back to Nick for a few closing comments.

Yeah, and I just want to thank Tim. He's been a valued member, of course, of our leadership team through one of the most consequential periods of time in our history. We've got a long history. He and I were talking the other day. If you look over the course of his tenure, we've taken production cash, cash costs from about $2.16 an Mcf to $1.18. That's a 45% reduction. Production on the other side of things went from 172 Bcf, and you compare that to last year's production, it was north of 500 Bcf. That's an increase of almost 200%. And then, beyond those things, you know, these other drivers of rate returns and intrinsic value per share, the EUR, cycle times, countless operational metrics have improved markedly over the past five years because of Tim's leadership. And I think most importantly and our team believes most importantly, the safety and compliance footprint that Tim leaves is second to none in the basin. And it really embodies the continuous improvement and excellence that we talk about. So that's a testament to his leadership, and that is a heck of a legacy to leave behind. And on behalf of the Board and the team, I want thank Tim on the call for all his contributions to the Company, and we look forward to the collaboration that he's going to bring with the rest of the team in the coming months and as we work to build around those accomplishments that we just talked about and take us to the next level. And rest assured if you're -- our ownership on the call and listening, we're going to squeeze every last ounce of effort and inside out of Tim in the coming months as we finish 2019 strong and set-up for what I think is going to be an impressive 2020.

Operator, if you can open the call for Q&A at this time please.

Sure. [Operator Instructions] The first question will come from Sameer Panjwani with Tudor, Pickering & Holt. Please go ahead.

Hey, guys. Good morning.

Good morning.

Maybe just start-off on the Midstream side of things with CNXM inflecting a free cash flow, how you think about drop downs in 2020? And can you help frame the retain Midstream EBITDA at CNX? And maybe also at the debt capacity at the MLP? And then finally with the heavy build-out of Midstream assets both internally and at CNXM nearing completion, how do you think about the strategic value of Midstream ownership going forward?

Hi, Sameer, this is Chad Griffith. I -- we have a couple of thoughts on how Midstream fits into the bigger picture here at CNX. I think first and foremost, we don't need to any drops and in either company's base plan to hit any of the guidance that we have provided. Both companies are performing very, very strong, very healthy companies without conducting any kind of drop-down transaction. So we don't need to do any drops to sort of hit our targets. And second, I think you already hit it. The Midstream business is really hitting an inflection point towards the end of this year. We're transitioning into our free cash flow -- free cash flow generation mode which is going to continue to improve the balance sheet and generate cash on a go-forward basis that growth provides a lot of optionalities at the Midstream business to just do a lot of exciting things with, sort of. Unfortunately the third point, sort of, the MLP market is what it is. And we are continuing to monitor that MLP environment and sort of monitoring it out on a go-forward basis. So sort of where the equity values are with the MLP market is makes it a little bit challenging to use that currency to do transactions with. And the last the balance sheet capacity and the optionality there -- it gives us some options to sort nimble around the edges on some of these things. But certainly none of that is in any of our base case forecast or guidance. As far as retained EBITDA there is a small amount of retained EBITDA from the Midstream business still at the upstream level. It's not only 9 -- it's less than $10 million. I want to say it's really maybe $5 million, $6 million.

So that's for the jump --- this is Don that's for the puts in the DevCo structure…

Correct.

…currently slowing. There is still build-outs to happen both at the DevCo III area which we've talked to could be a significant EBITDA generator once that occurs. And there is the water business in the Virginia Cardinal states asset that have -- currently producing cash flow that are more mature assets that could be looked at to be dropped at some point in the future.

Okay. And on those two kind of last assets the water system and the gathering system, I guess, any kind of ballpark estimate for what that EBITDA could look like getting into 2020?

So a lot of that obviously depends on the commercial arrangement that you would put in place between CNX and CNX Midstream. We have highlighted in the past that the Cardinal States opportunity between where it -- the transitioning from the TICO into Transco Zone and the flows that's going through there to be $10 million to $25 million type of an EBITDA opportunity there. And then water business, obviously and the commercial arrangements will dictate what the ultimate would be. We've looked at historically at the Analyst Day we walked through what potential general rates would point that to be and that was the at the time closer to $50 million growing as the volumes grow over time.

Okay. Okay. That's helpful. That's a pretty good overview of part of some of the part's opportunity at CNX. I think one other piece that gets overlooked sometimes is your feet-acreage position. And if I recall correctly, CNX has one of the highest NRI positions in the basin. I wanted to get your thoughts on potentially monetizing some of those that take advantage of higher return opportunities such as buybacks?

Yes. So we have sold a lot of acreage in businesses if you look historically at CNX and as a predecessor CONSOL Energy. So we've done a lot in that arena over our overall history here and we know how to get M&A transactions done. When you look at doing overriding royalty sales, the balance you to watch and what we talked through on the call today one of our strategic advantages, we believe is our cost structure. So adding cost to our future drilling locations really, while it may help in the near-term it can really hurt your cost structure and your competitive advantage in the long-term. That being said we do look at transactions and as Nick has mentioned we follow the math. So it's a balancing act is what we do and choose not to. The good news is as Chad mentioned, we don't have to do anything. We don't need to do any of these to fix our balance sheet or to help us out to fund our business. So we're able to opportunistically look and if the math makes sense we'll pursue it. But those pieces that add cost to your structure, we're picky on.

Okay, okay. That's helpful, and if I can just squeeze one last question in here. Just on the 2020 outlook, I'm just trying to understand the capital allocation rationale that results in production beyond the hedge book. Seems like given current strip, any excess volumes would generate marginal cash flow. So, just would appreciate your thoughts there.

Yeah. And as we’ve talked about, we used the forward strip to make our decision-making, and as we've learned here over the past six months or six years, the forward strip is very volatile. So, we keep a close eye on it. Hence, while we do continue to maintain a very healthy hedge book to ensure that we're making returns on capital, we do spend. We think right now these pads generate adequate returns that we're all ultimately always watching. And we do have flexibility built into our go-forward business model in 2019, and especially obviously in 2020, since we're coming out pretty early with our initial viewpoint on 2020 to dial that back or dial that up as conditions warrant. As you look in it the next couple months, the weather patterns will really influence pretty majorly on how gas prices change, and we have a flexible enough plan in front of us to morph to fit what's best in that environment.

Okay. That's really helpful. And thanks for that, and congrats on the retirement, Tim.

Thank you.

The next question comes from Welles Fitzpatrick with SunTrust. Please go ahead.

Hey. Good morning, and yeah, I echo that congrats on the retirement.

Thank you.

So looking -- and I know this is probably getting way ahead, but looking at the 2021 kind of soft guidance, should we basically be thinking about that as the way that CNX exists in the current strip environment and the kind of $2.25 to $2.75 environment that you guys will essentially stay flat to flattish, and become a free cash flow machine going forward? Is that how you all are looking at it internally?

We've tried to stay very consistent in our views and our thoughts, and really focusing on risk adjusted returns and creating NAV per share over the long haul intrinsic value per share. Now, to do that, you need to produce and make cash flow, and you do have to have a healthy balance sheet. So, as we're looking forward into the forward strip and where the price deck sits at $2.75, gas price environment is very different than the $2.25 gas price environment. So we're trying to build a company and a machine that can work in low prices and be ready to accelerate and take advantage of high prices. And as we've done in the past, if we do see the ability and the opportunity to catch at higher rates -- higher pricing and grow, that's something we will consider, ultimately as we've done in the past. We'll look to do the same thing, which is hedge the gas, first, ensure that you're going to have the cash flow growth and then return on the capital that you spending before you spend it. And if the gas prices stay lower for longer, we're in a good strong position to stay at a minimal level and keep a healthy balance sheet, and just look to make that next incremental investment based on the conditions that exist in 2021.

I think the catch phrase for 2021 is really optionality. If you think about what we're doing, we're not trying to solve at the end of the day for free cash flow or for production growth or things like that, like Don said, you follow the math, you follow the returns and you want optionality, whether it's balance sheet, whether it's cash flows or whether it's an asset portfolio. You want the optionality to be able to pivot as you get closer to 2021, across those three big opportunities of drill bit capital investment, a share count reduction and debt reduction. And we look at 2021, based on what we are expecting to perform in post for the balance of 2019 and going into 2020, we should have a substantial level of optionality to be able to pivot and optimize no matter what gas prices do, whether it's the $2.25 or the $2.85 role that we're faced with in 2021.

Okay. Now that makes total sense, and I guess then, the kind of fundamental or the non-fundamental driver that might impact would be a share count rally, because presumably the opportunity cost then of putting it back in the ground would go down. Is that a fair enough interpretation?

Yeah, that's -- you know, the three, like I said are -- like you mentioned, there's -- where the shares are trading at versus what we think we implied NAV per share of the Company is based on the forward strip, there is what this rate returns are on the drill bit based on all the metrics on the performance side of the operations, as well as the gas price strip. And then the last piece of that is what is leverage ratio doing based on the cash flows because of commodity price. And where that all plays out depends on all three of those factors. So going into 2021, we should have a substantial level of capacity, flexibility, optionality to pivot across those three and weigh one more than the other based on what the math tells us.

Okay. No, that's perfect. And then just one more, if I could drill in a little bit. On the well costs on Majorsville, obviously that's come down a whole heck of a lot. Can you talk about -- presumably most of that efficiencies, can you talk about the repeatability of that? And also within that question kind of the difference between 6E and 6S and what was causing those deltas in cost there?

So I think the – yes, it's repeatable. We have just efficiency doing what we've been talking about with the Utica for the past several quarters. We've talked about the challenges drilling through the vertical section, the salt section and some of those other formations where -- we have to get through to set our deep intermediate strength that's where a lot of the challenges lie. The well that had little -- slightly higher cost, we had a few day delay there with some drilling issues, but nothing major that we didn't overcome. But when you look at the overall cost there, we've been talking about this target at $12 million and -- $12 million to $12.5 million for the last 1.5 years or so. And we have mentioned before, we saw a clear path to this number and we think, it is very repeatable. Well results will standup as well we think. And so, we're excited about what the Utica brings to the table for us and the results that it'll generate.

That’s great. Thank you. Thanks so much and congrats on the good update and good guidance.

The next question comes from Kevin MacCurdy with Heikkinen Energy Advisors. Please go ahead.

Good morning guys. How does the depth of the deep Utica change as you go east to west in Southwest PA? And is there any difference in the difficulty of drilling those wells?

There is. We've talked about the deep Utica in Pennsylvania it is much different than the Marcellus, it's much more compartmentalized. It varies from area-to-area and not just from Southwest PA to CPA, but even within Southwest PA there are different compartments. Geo-hazards in some areas are much more challenging. And that is where I really think we have been able to differentiate ourselves and achieve these numbers that we've got laid out here. We've talked about the use of seismic to place laterals properly to avoid geo-hazards and we're in the process of doing that. And I think you'll see more results like this as we move forward.

Okay. And I think earlier you said 12 Utica wells in 2020. What is the locational breakdown of that? Are they all in Southwest PA?

Yes. They are not all in the swift to Utica. We have a pad in Monroe County as well which are included in those numbers.

Okay, that’s helpful. Thanks guys.

The next question will be from Holly Stewart with Scotia Howard Weil. Please go ahead.

Good morning, gentlemen. Maybe just a few questions on 2020 you referenced some cost savings. Can you just maybe talk through, what you're seeing there doing there? Is it just a per unit given the growth? Or -- well and then maybe reference what you're thinking on the service cost assumptions within that plan?

Yes. So we see both. I mean Holly obviously with the growth, it helps on the scalability as Tim mentioned earlier. Our cost structure looks great amongst peers, but even better whenever you realize that there is room to improve just on scalability. And then second on an absolute dollar standpoint. I mean, we are driving for more efficient use of our realtime operating center and adequate vendor management. Obviously the forward cash strip provides challenges, but also it provides potential opportunities whenever you're looking to the service providers.

Okay. And then maybe Don it might be two in the least for the call for this, but just thinking about the outlined growth assumptions for 2020. Have you ran sensitivities on the free cash flow number, if you were to sort of do a flat exit-to-exit production from 2019 to '20 versus the 12% annualized growth?

Yes. We do. We do keep pretty close eye in balancing really. We've talked about it over time sort of a minimum level of activity, we wanted to have a healthy efficient running business and that leads to our CNX Midstream commitments. It utilizes the service contracts that we have a place and keeps a nice strong healthy balance on our water. So there is some mobility to potentially dial back potentially, as gas prices unfold here over the next few months. I do think weather -- finishing up the end of summer and likewise the first, call it, October/November as you're heading in we'll accept the realities of how gas will unfold in 2020. And if it heads one way we'll try to lean back even more than we have. And if it heads the other we have optionality to do even more in 2020 if it warrants it.

Okay. So -- and maybe Nick then just thinking about the high-level discussions that you had with the Board on the growth in this commodity tape. Is there some, I guess color you can provide around that? And going with the higher growth rate in 2020 versus maybe starting at a lower level and if commodities respond popping up?

The growth rate is a result. It -- we don't think much of it beyond it's just the result that spits out at the end of something else that we're solving for. And really the discussions across the management team and the Board have been across three big opportunities right now, a significantly discounted share price; some pretty compelling rate of returns because of our performance metrics and cost structure on the drill bit. And the ability and desire of Marcus to see a stronger, well maintained, healthy balance sheet. So that's the balancing across those three when we run our math on rate of return. And risk adjusted returns. It leads to some of the results, one of which was the production growth that you're referencing, the other one being a free cash flow in 2020. And what we do is, we monitor those. And recalibrate those. And recalculate those constantly as the forwards change. And frankly, if some of our internal data come in, like the D&C cost, on Utica that Tim had mentioned. And we optimize that on a running ongoing basis. So, when we get to the Q3 call, if commodity prices change significantly. We'll update, you know what, if any changes we've seen with respect to the balance in 2019 and then the 2020 program. Whether it's capital, free cash flow and share count and balance sheet and all of those things wrapped into one.

Okay, that's helpful. And then, maybe -- maybe for Don, you referenced the $800 per foot, on the longer lateral pad. Do you have a target for Marcellus well cost for 2019, you could share?

Well, I think, Holly, this Tim. I think the target around $815, a foot I believe. And you know a lot of that is lateral length dependent. And -- but we're -- we've seen those costs. We've achieved it. They are not aspirational. That's built into the plan. And we still look for ways to continue improve that. And one additional comment, I wanted to make. So I think it was Wells question on Majorsville 6. The -- I believe it was F Well that had the higher cost that was also a pilot hole. And we did a little bit of science work on it. And that's where some of the additional cost came from.

And when we do look at our cost per foot, it's important to note too, that we did include flow back. And we do kind of look at it as everything you need dollar per foot type place. So, Tim has laid out the targets. We've laid out on the efficiency, efficiency push to reduce spend across, all the bucket. So, I feel good. We've already kind of got there. And we're looking for ways to improve.

Okay, that's helpful and then, maybe one final one, if I could. Just, Tim, any update to share on the status of the Shaw pad?

We're continuing to move through that. We still plan to complete the three remaining wells. That won't have an impact on 2019. But it will -- they will get completed. We're just keeping that somewhat flexible. So we can work to make sure, we work through all the appropriate issues, with the regulatory agencies and all parties involved.

Okay, great. Thanks, guys.

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

Thank you and good morning, everybody. Hey, Tim congratulations on your retirement, and Chad, congratulations to you as well. And my question is for Tim. So, Tim, what further operational improvements do you look forward to, as you fill out your tenure there at CNX and as you kind of watch the Company from a distance after you retire? And Chad, I'd love to get your insights as well.

Well, I think when you look at, what we highlighted on Majorsville 6 and the Utica, that it really -- it really kind of stands up everything, we've said about the Utica in the last couple of years. We have been upfront runner in the Utica. And will continue to be. But, I think it shows that, the numbers that we've been putting out there and on the Utica. And what we expect of it is coming true. There's always room to continually improve. We'll look to improve those drilling efficiencies. Now that we've seen the $12 million mark. I don't think it's unreasonable to think that we can get down in that $10 million to $11 million mark per well. Obviously, some of that depends on lateral length. And then there's always room. We continually look for ways to optimize our completion efficiencies. It's not just about getting the cost down. But it's also about improving well results and maximizing that EUR per 1,000 foot.

And this is Chad. I'm just super excited to get this opportunity. And you know I've been working with these guys for years at this point. So, I really want -- looking forward to working with this team further. Tim's put together a heck of a team downstairs. We've got a lot of talent. Really looking forward to working more closely with those guys. And really bring in to that team, I think what we've been able to bring in to the Midstream team over the last nine months, 12 months, is really just a focus on making sure that every dollar we spend is earning a return that is creating value for our shareholders. And just really continuing to draw that focus on cost and that every dollar matters.

That's helpful. And Tim, I know you commented on the Utica, but any kind of comments on further improvements in the Marcellus?

Well, I think Marcellus, we saw with our Richhill 71, what we did there, $800 a foot. Using our real-time operational center, there's ways we can gain efficiencies there, through geo-steering, through management of our completions in that operation center. There's always room for improvement. I think a lot of times we -- people think that you're going to hit a wall on improvements, but technologies change, processes change, equipment changes. And whether it's fluid systems, bids, drilling rigs, frac crews, you're looking at what we're doing with evolution. That's a perfect example. The all-electric frac fleet and the efficiencies we're gaining from that. We'll continue to find ways to utilize new technologies, processes and make things better.

Very, very helpful. Thank you, guys.

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

Good morning. My first question is on West Virginia. How do you think about the West Virginia production and the activity levels going forward? And also, could you maybe discuss safety and well commitments in West Virginia and how they fit into the 2020, 2021 program?

This is Chad. Those two questions are actually related. As we think about West Virginia, particularly actually Hillsborough area, for the cadence that we're thinking about down there is roughly a pad a year, give or take. And that schedule is sculpted to meet the drilling -- the minimum volume commitment associated with CNX Midstream. And so those are all sort of linked. And we're doing it in a way that that's really optimizing that drill program to -- for the benefit of those CNX and CNX Midstream.

So it seems like the FT commitment is not something that drives the program, right?

Well, that's correct, because we at CNX -- because I'm sure you're aware we have a very, very low -- we have relatively small FT book relative to our peers. Our FT layers are all predominately filled. And so it's really like the incremental drilling decision is not driven by a need to fill FT.

And this is the same case, how Utica, you basically saw old volumes in basin and it seems like you don't have any well commitments in Ohio, Utica right, but still planning to complete one pad a year right?

So, as far as the Ohio program goes, we've got a few wells in the plan for this year. I think incremental opportunities on a go-forward basis are a little bit more of a case by case decision. None of those decisions will be driven by well commitments or FT commitments. It's really just optimistic if the rate of return justifies investment in other wells in that area.

Okay. And my final question is on basis differentials. I saw that you guys are guiding through slightly by the basis differentials next year. I think it's due to high in-basin sales. I just wanted to confirm that or maybe you see some other developments that would explain that?

We do. Because of our low FT book, we don't rely on expensive long-haul FT to move our gas to other basins. With the way that's resolved, there’s a lot of our peers who have that long-haul export capacity, a lot of that is under water at this point. So we've been able to avoid that burden from our cost structure. But that does result in a lot of our gas being sold in-basin. And so in order to offset the risk of the volatility that that local physical realized price, we've been able to -- we make sure we match our sales with a matching basis hedge to take the -- so that's a matching financial basis hedge that takes the risk out of the physical sale of that product.

Before our basis guidance, it's just a strip that cracked in July. So it's a proportionate mix on the sales points, which we show in the appendix using the strip from July to calculate the basis. So no views, just the strip.

Okay, okay. And the last question, if I could. In the press release, you mentioned that transportation and gathering line that is slightly higher due to high expenses to CNXM. Is it related to gathering fees, is it just like an annual escalation of the annual -- of the gathering fees? Or what is it?

Predominately that bump was caused because of the handful of pads we turned in line in the first two quarters of the year. They are a disproportionate number; roughly half of those were wet wells. And let me rephrase that. One of the pads was a wet pad and one of the pads was a damp pad and that damp pad was wet enough. And based on the relative NGL and gas prices, we elected to take that gas to processing. So sort of net-on-net we took two pads to processing out of the handful pads returned on line first half of the year. That's disproportionately high for us. And so it just was a temporary swing where our GP&T went up slightly for the first half of year.

Got it. Thank you so much for taking my questions.

Thank you.

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

Great. Thank you. We appreciate everyone taking the time to join us today. And I look forward to speaking with you again next quarter. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.