CNX Resources Corporation (CNX) Q3 2019 Earnings Report, Transcript and Summary

Good day and welcome to the CNX Resources Third Quarter 2019 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Tyler Lewis, Vice President of Investor Relations. Please go ahead.

Thank you, Nicole, and good morning everybody. Welcome to CNX third 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; and Chad Griffith, our Chief Operating Officer. Today we will be discussing our third quarter results and we have posted an updated slide presentation to our website. To remind everyone, CNS 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 11:00 AM Eastern today, which will require us to end our call no later than 10:50 AM. 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 have laid out for you in our press release today, as well as in our previous Securities and Exchange Commission filings. We will begin our call today with prepared remarks by Nick, followed by Chad and then Don, and then we will open the call for Q&A. With that, let me turn the call over to you Nick.

Thanks, Tyler. Good morning, everyone. Thanks for joining. I want to start by highlighting a couple of metrics and data points that we think become of heightened importance and the challenged commodity price environment that the industry is looking at today. These metrics, I think they matter across all phases of the cycle, but they are especially important and significant during the more challenging portions or parts of the cycle. And first, I'm, going to talk about our inventory and our base plan. So, let's talk about what we designate as our Tier 1 core inventory that's shown and summarized on Slide 4, so I'll be speaking from Slide 4 in the next minute or two. CNX has one of the top tier acreage positions across the Appalachian peers. You can see almost 1.2 million net Marcellus and Utica shale acres that we control, and focusing in on the core Southwest Pennsylvania Central type curve region, you can see we've got approximately 70,000 net undeveloped acres. And using an average lateral life of 9,500 feet and 750-foot spacing, you need approximately 160 acres for each Marcellus well that you want to drill and complete. I think the slide says 163 acres to be exact. You divide that 163 acres into our net controlled undeveloped acreage in the region. That gives you approximately 427 locations. Our successful development program is averaging about 36 wells per year in this area when you look at 2018 to 2020. So, assuming a consistent go-forward development program, you'd have enough drilling locations to support a dozen years' worth of drilling. And remember, based on the conservative way we show our remaining inventory, any leasing we do in the future adds to our net undeveloped controlled acreage position, which in turn is going to add to our inventory position allowing it to grow over time as we invest in land capital. Now another active area in our development plan is the Shirley-Pennsboro location, an area in West Virginia. As of year-end 2018 we have 76 locations. We expect to turn in line roughly one pad per year in this area which would give us about 12 years of inventory there as well. And as you can see on Slide 4, due to the prolific nature of our inventory, 40 wells a year actually grows our production. So in just these two Marcellus areas, CNX has the ability to methodically grow production for over a decade. Now that the inventory for our decade long based plan has been reviewed, I’m going to spend a minute on the other main areas that we have and that we're excited about. These areas are going to allow us to either A, add incremental drilling and production growth of the program over the next decade as gas prices warranted; and or B, add substantial inventory for years 13 and beyond. I'll start with Southwest PA Utica. Our stacked-pay strategy here has given us substantial flexibility to add activity quickly if gas prices improve or go about a capital efficient drill program after our Southwest PA Marcellus field is depleted. And in the meantime, we will continue to do a couple of wells a year to facilitate our blending strategy of further refining the cost and reservoir characteristics. Another area in the next area I want to talk about there is CPA where the Utica reservoir has been repeatedly very prolific and where Marcellus is going to be able to be the stacked-pay opportunity for that area similar to what Southwest PA Utica served as the stacked-pay for Southwest PA Marcellus. So the bottom line is that we have a robust inventory of low cost, low risk, high margin, high EUR Marcellus locations to fuel the base case for the company for over a decade. And the rest of our assets are strongly situated to provide us with lots of efficient optionality throughout the next decade and a large quality inventory for the company to utilize for decades to follow. Let's now talk about costs, and that's really, I think, highlighted best on Slide 5. So Slide 5 shows how CNX has top-tier production cash costs when you compare us to peers despite producing the second lowest amount of volumes in the basin. And we show costs on that slide with and without the benefit, whether it's through consolidation or the cash distributions that we receive from our midstream MLP CNX midstream. If you include those benefits, our costs start to decline meaningfully in towards the $0.78 per Mcfe that you see to the left of the slide. Now, of course, in a commodity business, having the best assets that's not enough. That's a good start, but it's not sufficient. You also need best-in-class cost. And the only sustainable place over the long term is at the bottom end of that cost curve. We've made great strides, but we are far from done, and we're going to continue to focus on driving these lower which is going to further strengthen our company. Slide 6 talks about and summarizes the active management of one of these cost areas really in action. We are well on our way to achieving our $30 million in expected savings that were above and beyond the prior 2020 guidance numbers when you look at SG&A. During the third quarter, we combined functions that existed across both our upstream and midstream teams. We flattened our organization, optimized workflows to help streamline decision making. And we've already realized roughly $25 million in expected savings in 2020 when compared to the previous guidance. CNX’s 2020 expected SG&A on a standalone basis is over 50% less than the peer average on a trailing 12-month basis. And as the slide shows, Slide 6, we don't set a target then sit back content with what we've achieved. We're constantly looking for ways to get better and continue to optimize based on never-ending changing conditions. This effort is what drove our journey since 2018 over the past couple of years. You can see that when you move left or right on that slide. Let's talk about hedging on Slide 7. The slide shows the updated hedge book compared to peers. CNX is substantially hedged in 2020 and 2021 with the strongest realizations in the basin. This is the case for 2022 as well. For 2020, using our updated guidance, we’re 94% hedged at $2.97 in Mcfe and for 2021, we’re approximately 76% hedged and that's based on the consensus numbers. So, we’d be even more hedged if you assume flat production. This hedge book, it was built to protect our returns. It was built to protect our capital structure, and it allows us to stay strong in the downturns and grow in the upturns. Our hedge book continues to be unrivaled, and it's of pivotal importance in this commodity cycle. And you can see that on the next slide in terms of how it's protecting the free cash flow we plan on generating. So, let's talk about free cash flow that's on slide 8. Despite the macro environment gas prices and NGL prices getting worse, since our last update, CNX improved our free cash flow projections for 2020, and we also added cash flow to 2019 as well. Now, you'll see 2020 NYMEX came off $0.15 since our last update along with 2019 NYMEX and NGL prices coming in lower as well. Don's going to go through the updated guidance in detail in a couple of minutes, but in general, I'll tell you, we're able to increase our free cash flow in spite of the lower prices by doing things like reducing our costs, lowering our capital, and streamlining and reducing our activity. And even with the lower activity levels, we increased our 2019 production guidance, and we're still projecting to grow our volumes in 2020. A combination of increasing our already positive free cash flow in 2020 while still growing production that is certainly unique among the sector. So, in summary and wrapping things up, looking at Slide 9, you can see that we continue to differentiate ourselves through three main advantages: first, our marketing strategy; second, our cost structure; and third, of course, the asset portfolio. Our competitive advantages and approach, they're allowing us to more effectively navigate a challenging commodity and macro environment, and these advantages they allow us to approach a lower price commodity cycle from a position of strength. And even though gas prices got weaker this quarter, CNX resources just got stronger. These advantages and the unique philosophy that we deploy, they've continued to separate us from our peers, and we're positioned very well for whatever lies ahead. And with that now, I'm going to turn things over to Chad, who's going to provide an update on operations.

Thanks Nick. Turning to operational highlights for the quarter on Slide 11, production was 128.3 Bcfe or 5% decrease over the prior quarter but up nearly 8% over the same quarter from last year. This is in line with what we expected and directionally guided to last quarter. We turned 24 wells in line in the third quarter while drilling 15 and completing 20. The majority of the wells came on later in the third quarter which will set us up for a strong expected production in the fourth quarter. Slide 12 highlights the blending strategy that we are employing in Southwest Pennsylvania. We have several damp Marcellus pads being blended with dry gas and entering dry gas systems and avoiding expensive processing. As part of that strategy, we brought two Southwest PA Utica pads online during the quarter. While it's still too early to go on specifics on well performance for these recent wells, it looks like pressures are good and our blending plan is on track and generating strong rates of return even in the current commodity market. As such, we continue to focus on our core Southwest PA development plan at the foundation of our steady state go-forward plan, which will include a couple of Southwest PA Utica wells each year as part of our core blending strategy. Along the way, we will continue to collect data on Southwest PA Utica which will improve our understanding, which we expect will improve results over time. Don will go into more details in his commentary about guidance changes. But we did cut back on activity as a result of the recent commodity price changes. This reduced activity is allowing us to operate very efficiently and is setting us up for more efficient 2021 and beyond. Beyond the scale back in activity, we are redoubling our efforts to drive down operating costs and improve capital efficiency. Some of these efforts, such as the process we completed this quarter of combining our midstream and upstream teams, will pay greater dividends over the next several quarters, while others, such as our focus on optimizing our water portfolio, are already paying off. For instance, better reuse of our produced water during the third quarter was the main driver in reducing production cash costs by $0.05 per Mcfe quarter-over-quarter. Water reuse has become a popular subject lately, but we've been planning for it for several years. We've built a basin leading water system consisting of pipelines, which allow us to significantly reduce the number of water trucks we use and storage facilities which provide the buffer between the steady production of produced water and the rapid use of water during completions. The final piece of that water system in the Ohio River waterline, which was completed and brought into service and provides the additional water needed for our completion work. On the capital side, we are continually evaluating our D&C capital plan with respect to changing commodity prices and service costs and how our D&C investment opportunities stack up against our other capital allocation alternatives. We follow the math, and the math has led us to reduce our activity, resulting on our updated guidance which Don will discuss in more detail momentarily. For the capital we do spend through D&C, we are focused on maximizing risk adjusted rates of return while continuing to operate in a safe and environmentally compliant manner. Slide 13 provides some of these highlights from the third quarter. With drilling, we averaged 13 days per well and averaged almost 5,900 feet of drilled lateral footage per day. Also, our rig moves averaged 2.75 days. On the completion side, we set a record of fracking 15 stages in a 24-hour period and continue to see the benefits of the evolution all-electric frac fleet. In addition to pump efficiency and operational flexibility, we are seeing real life savings of $250,000 per well and fuel savings by burning natural gas over diesel. For us, the process of optimizing D&C capital does not mean simply solving to the lowest dollar per foot metric. What we are solving for is rates return. That said, dollar per foot is an important metric that contributes to rates return. But there are many ways in which we could further reduce our D&C per foot number, but some of those ways do create problems down the road and lead to impaired rates of return on that investment opportunity. Nevertheless, with the math and engineering support, we can deliver industry-leading dollar per foot numbers such as on our Shirley 38 pad which just turned in line in West Virginia. Where we delivered a 5well at an all-in $640 per lateral foot inclusive of capital, beginning with ground-breaking, through turning line. Just to sum it up, the team continues to execute and is constantly pushing for more efficiencies and cost reduction. Our capital efficiency continues to improve and is driving our corporate strategy. With that, I'll hand it over to Don.

Thanks Chad, and good morning everyone. Slide 15 shows some of our financial results for the quarter. Consolidated adjusted EBITDAX for the quarter was $204 million or $1.09 per outstanding share. And standalone adjusted EBITDAX plus distributions in the third quarter was $159 million or $0.85 per outstanding share. Despite weaker gas prices compared to last year we were able to maintain strong operating and fully burden cash margins. Next, before I get into our guidance specifics, I wanted to spend a few moments discussing how we have built a flexible company that is able to adapt as conditions change around us which you can see on Slide 16. And like we have said many times before, we make decisions throughout the course of the year in a dynamic fashion. Variables in our industry change quickly and frequently. And we modify and change our approach accordingly throughout the year. We built the company to navigate a downturn and you are seeing that plan in action now. And just to be clear, we have not only positioned the business to be well on the downside case we have also created a lot of flexibility to accelerate activity of commodity prices and conditions improve. We have a substantial inventory of low cost, high margin locations with infrastructure in place to support quickly adding activity. And as we have shown in the past, we are willing and able to sell assets which is another way to quickly and meaningfully participate in an upside scenario. Now let's shift to looking at our updated guidance for 2019 and 2020 starting on Slide 17. There's a lot of information on the slide so we'll go through a high level summary first and then talk to a few of the details. In general, the commodity price has gotten worse since our last call. And over the second half of 2019 and all of 2020 we reduced our capital guidance by approximately $80 million. We reduced our consolidated SG&A spending guidance by approximately $35 million. We decreased our production guidance by approximately 17 Bcfe 00:17:55. But we are ultimately able to increase our CNX standalone free cash flow guidance through the end of 2020 by over $30 million by actively managing the business. Now, for a few of the specifics, for 2019, estimated production volumes are up 15 Bcfe to 530 to 540 Bcfe while projected capital is down approximately $17.5 million based on the midpoint. In 2020, projected capital is down $60 million from the last update. And due to the 2019 production acceleration coupled with the 2019 and 2020 CapEx guidance reductions, production volumes are expected to be down 35 Bcfe based on the midpoint of the updated 535 to 565 Bcfe guidance when compared to the previous update of 570 to 595 Bcfe. And like Nick has already mentioned, based on all of our changes, we were able to increase our free cash flow guidance to $146 million compared to the previous guidance of $135 million despite the fact that gas prices are lower than they were at the time of our Q2 call. Also, it is important to note that these changes are not creating a one-time benefit for 2020. The plan has consistent activity throughout the year, and as you can see from our guidance numbers, we have not yet reduced non-D&C capital, although we will actively manage it as the year unfolds as well. As a matter of fact, this guidance change actually makes our 2021 and beyond path easier, saving some locations for later and having less wells declining in 2021 and beyond. But how should you think about the free cash flow potential of CNX moving forward? Well, in a maintenance of production-type program, we would expect to generate a significant amount of free cash flow each year using the current forward strip. In fact, under this scenario, we would expect to be able to generate enough free cash flow from now until the end of 2020 to 2022 to pay off the majority of our outstanding 2022 notes using our own free cash flow from the business. And remember, we are using the current forward strip for our forecasts. Our numbers would obviously look better at the higher than strip forward-looking gas prices typically used by our peers. Slide 18 highlights some of the additional guidance updates. One of the bigger updates here is SG&A. For 2020, we are reducing consolidated SG&A guidance by $25 million compared to the previous guidance update, with 2019 coming down as well. And as you can see on slide 19, CNX screens very well when looking at absolute SG&A dollars on a standalone basis. Slide 20 is an update of the production profile we expect through next year. As you can see, it is fairly consistent throughout the year with a bit of growth coming towards the end. We expect to turn in line approximately 47 well, 35 in the Marcellus and 12 in the Utica. And to be specific, the breakdown of the 12 Utica wells is as follow. One Southwest PA Utica pad consisting of four wells, which supports our blending program; one Monroe County, Ohio, pad consisting of five wells and one CPA Utica pad consisting of three wells. And as we have said during our last earnings call, we will pay attention to all the variables and adjust plans accordingly as the year unfolds. Slide 21 showcases how our 2020 free cash flow is protected from commodity price changes by our hedge book. The fact that we chose to produce less in 2020 results in less gas sold at open prices and as such our 2020 production is now 94% percent hedged. With our new plan our cash flows is even more protected. With a $0.10 move in 2020 gas prices only resulting in a $5 million change to our standalone adjusted EBITDAX plus distribution demand. And like we have said previously, if gas prices get better, we can add activity or look to sell assets and participate in the upside when it comes. Slide 22 shows some of the details on how we think about our capital structure and balance sheet. As we have said before, we look at these things holistically and view asset quality, cost position, flexibility in your business with lower fixed cost and revenue and cash flow productions via hedges, as well as the typical leverage ratios and liquidity metrics. And as you can see on slide 23 and 24, our balance sheet is looking stronger and stronger versus our peer group and its challenging price environment. CNX’s leverage profile screens very well compared to our peers especially when including off balance sheet obligations such as FTE which the slide show we have prudently managed. The team has been hard at work building a company that has the flexibility to navigate through tough commodity cycles and in the environment that we are in today, it is paying off. Our team, our asset base, our strong hedge book, our low-cost structure, and our philosophy have positioned us to adapt and thrive in that environment. With that, I'm going to hand it back over to Tyler.

Thanks, Don. Nicole, can you please open the lineup for Q&A at this time?

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

Good morning and congrats on the strong guide there.

Good morning. Thank you.

Does - I think I know the answer here, but does it modestly slower 2020 plan, does that change any of the kind of theoretical drop cadence in your mind?

Yes so, we haven't given any guidance on what drop cadence would look like. We have found it important to not meet those in our go-forward plans from the upstream perspective and as well as the midstream perspective for that matter. But obviously, as inventory last longer and different areas get pushed back the need to build infrastructure in some of the new areas is pressing at the moment. So, in general, we'll figure these out as time requires, but we've got time and both companies have the wherewithal to do it when it makes sense for both.

And you guys mentioned a couple of times in the prepared remarks about your ability to add rigs quickly if prices improve. Is there - can you talk to how you think about that is that sort of IRR. Are you solving for IRR, are you solving for free cash flow, et cetera?

Well for us, it’s always kind of accelerated return. And we compare the rate of return from the incremental drilling activity to the other opportunities we have for capital allocation. So, for us it's always going to be a matter of looking at all the different variables and all the different inputs and what the rates return ended up being when you compare D&C capital versus whether it’s shared buybacks, debt reduction, or other use of the capital.

And the variables that exist at the time of the decision, obviously, how active and accessible the debt markets are, change how you run the mechanics and math on this as well as with the gas price change looks like. Is it just a quarterly change or is it a forward strip modification, and do we have the ability to hedge and to lock in some of those additional cash flow streams?

And then just one last one for me. Can you - and I know your midstream contracts give you protection from the vast majority, if not all of it, but can you talk a little bit to the recent dips and volatility at down south and M2 and kind of how you think that might shape up throughout the end of the year in 2020?

Sure well, I think a lot of the volatility in the local market, we had - there were some pipeline interruptions during the quarter particularly getting - gas o the Gulf. I think that directly led to a lot of the volatility you saw in the local market share in Appalachia. We've been largely protected from that through our extensive basis hedging program. And so, we've largely been isolated from that. When you look at sort of an all-in, including hedge realizations. But I think a lot of the volatility has been driven by like the uncertainty of the timing of getting those interruptions corrected and where the flow is going to be and where we're going to get that stuff online. And then as different producers and market participants figure out ways to navigate around those transportation constraints so, it just sort of led to a really volatile sort of Q3. And I think as we look towards Q4 and into the winter. I think what's happening in Appalachia is a little bit - of a microcosm what's happening more nationally where storage is getting full. We're getting up towards the upper end of what the storage levels are. We're getting past the five-year average storage levels. There's still a lot of gas coming out of the ground. It's leaning towards a sort of tight winter. And I think we're all sort of - we're all hoping for a cold winter. And so that - that storage balance and some of the transportation constraints caused by that pipeline interruption just caused, I think a lot of market volatility.

Our next question comes from Leo Mariani of KeyBanc. Please go ahead.

Just wanted to kind of ask a question around activity levels. I think when I look back at the update from 2Q. I think you guys had made a comment that said you had three rigs under contract until the end of the year in 2019. I guess, today's update talked about two rigs running. I was just curious kind of what happen there if you guys were able to kind of get away from one of those contracts and what are the costs associated with that.

Sure thanks for the question. We gave some really good efficiency towards during 2019. We were able to do more with less. So when we look at sort of the macro environment, the gas price environment, and how much we were getting out of the rigs we had, sort of we didn't need that third rig that necessarily hit the targets that we already set out there. And so, we began thinking, okay, well, how do, we restructure those and what can we do, to bring sort of our activities back in line now that we've gotten more efficient. And so, we are able to do some restructuring and we are able to sort of off-load that third rig a little bit earlier than previously expected, really a cost neutral basis.

And I guess, in your prepared comments, you talked a little bit more about how you guys are still going to have some production growth in 2020, but it sounded like it was a little bit more weighted - kind of later in the year. Is that just a function of you kind of having more second half tilts in 2020 kind of like you sort of had in 2019? Is that how we should sort of think about. I just want to sure if I heard that right?

That's a good way at looking at it. And you can look at slide 20 for a visual depiction of what’s sort of production cadence will look like in 2020.

And I guess, any update on Utica well costs. Obviously, you guys did a good job driving this down over the last year. Just want to get a sense of where those are today and where do you think that may go into 2020?

So that’s on the capital efficiency side. We're continuing to find ways to get better there. We are looking at every piece of the D&C budget when we plan for those wells. What's the most optimal decision to make on each component of that well design, on the completion design, on those production facility designs. The team - really challenging the team to look at every piece of that to make sure it's optimal from a rate return perspective. Because some of the, we've already announced the Majorsville 6 results prior quarter. Those were very, very nice with three of those four wells in the $12 million range and the fourth well at $15 million. But again - the higher cost from the fourth well is really due to some science frac that we do on that well. The other southwest PA Utica we’ve brought on line this quarter the MOR 10 it is a little bit higher in cost. I don’t think we’re going to disclose the exact number on that, but it was a little bit higher but what we did there, we installed liners on that well as we discussed last quarter that we had a number of Utica wells where we’re planning on installing these liners that this pad we installed these liners and drill the power costs.

And I guess just lastly on kind of the comments you made in the press release. It sounds like there’s going be a little more of a focus on debt paydown versus stock buyback. Could you maybe talk that a little bit I think Don, you had mentioned that a lot of it had to do with existing debt market conditions. Maybe can you just provide a little more color around that?

Yes, like we've tried to stay consistent with here - the last several quarters around how we think and the cash flow that's generated from the business, the free cash flow. The triangle of what we do with it - whether it's invested back into the business and to the drill bit or bolt-on land acquisitions, whether we use it for buybacks or whether we use it for the balance sheet okay debt reduction. We try to be thoughtful and disciplined and prudent. We take the long view on these - on those types of items and obviously the debt markets have changed really quickly over the last - over the course of the year and - really over the last few months even more so. So common sense tells you part of - a big part of the NAV per share and intrinsic value the business is the cost to capital and the risk associated with it. So in today's environment where the credit markets sit the - call it the prudent discipline thing to do is make sure that your capital structure is strong and solid. And the hedge book and everything we've built keeps it strong and solid, but as you peer into the future. I think everybody is learned here over the last decade. It's impossible to predict the future so we don't try to. We try to just ensure that the business survives works as healthy and is growing per share value over the long haul step by step along the way. So as we sit here today the best use of the incremental dollar - currently with all the variables in place looks to managing the balance sheet.

Our next question comes from Holly Stewart of Scotia Howard Weil. Please go ahead.

Maybe, Nick, I can start with just sort of a bigger-picture question. You're showing some clear advantages with your hedge book and lower cost structure allowing you guys to switch gears on capital allocation. So, maybe if you could just provide your perspective on the environment for 2020 and how you see the dynamics playing out and then, maybe ultimately how this makes you think about M&A?

Yes. On the first part of your question, Holly, I think if you look at the next well we could drill or the next share we could buy back or the next dollar that we could retire, all of them, as Don sort of lined up and the prior question have some pretty compelling rates of return, tied to them using the time forward strip. That being said, he did a good job, of course, summarizing why we look at free cash flow debt reduction as sort of first on the list at this stage on that incremental decision. Now moving forward, I think again the math and the process remains the same. So, we will continue to run the rate of return metrics. And the key point in what to do with respect to future capital allocation and especially with respect to things like drill bit will be Don's comment on what's going on with the price change that we're looking at. Is it something that we're seeing across multiyear, so we can hedge and effectively lock the rate of return in on or is it something that's more of a seasonal change for a month or a quarter and really not much has changed beyond that in which case, I would suspect that we hold back on additional activity. With respect to M&A, I'm sure there's some compelling cases out there with respect to what's available on valuation versus where they're trading at their value at today. But I can tell you that, when you start to think about the risk and then frankly, what we know or don't know about this, versus what we know across the street, capital allocation opportunities that I just mentioned within our own portfolio, we are way more comfortable staying focused on our own portfolio for the time being.

And then Don, you made a comment there at the end that I was just trying to understand. I think you said, the majority of your 2020, 2022 maturity, which we thought was something north of $875 million would be paid off with free cash flow. Do we do we get that right? And then maybe could you just help us understand that comment?

Yes. And so if you look, with the way I tried to characterize it was, we did give free cash flow guidance for 2020. And we also laid out what a MOB capital program all in would cost to hold that type of production level through several years. So back of the envelope, I think you can kind of get there with those pieces. We haven't given official guidance for 2021 and 2022. So I don't want to provide official guidance there, but in that math, you quickly get to cost significantly more than half of the 2020, 2022s, is being able to be paid down from cash from the business. And then when you add in to different options that we have at our disposal, coupled with - we’ve always sold assets in all parts of the commodity cycle. They're not always chunky, but there are asset sales going on at this company all the time from surface to right of ways, to some of the smaller, under the radar things that provide cash inflow across the year-over-year as well. So to kind of help frame the cash flow projections and how we think about the risk associated with this 2022s and managing them in multiple ways instead of only having one option of our disposals is what we're trying to set up.

So just to make sure I understand, if you're saying if you went in 2020 through 2022 at a maintenance capital program, the free cash flow generation of that would throw off would cover the repurchase of the majority of that note?

Yes. Like I said, we wouldn’t want to get in 2021 and 2022 guidance at this point, but with that MOR capital and the hedge book that we have and the line of sight on cash flows, we feel good that there's - the majority of the 2022 could be handle with cash from the business and in the meantime we still are always looking at every option to manage the capital structure of the company. So, I just wanted to provide a little bit of color without getting into the specific guidance.

Yes. That's helpful. And then maybe, Chad, I think you pointed to slide 20 for sort of the production cadence as we move through the year. Is there any color you can provide on how that capital would be allocated? Is that sort of a linear program? Should we follow prior year cadence?

It is expected to be a linear program at this point in time.

And then just maybe one final one for me. Can you all give an expected to count that year-end 2019 and 2020?

Yes. Oh man, I'm sorry, Holly, I jotted those numbers down earlier, but the reality is that when you think about working inventory from 2019 into 2020, when we look at the activity, we had planned for 2020 between roughly two rigs and the frac crew or so, we are basically staying in pace. So, the amount of work and inventory we ran 2019 with, we complete that - some of that inventory in 2020 and we replace that dock inventory with drilling activity in 2020. So, as we look at 2020 and the capital program, we've laid out for 2020, our working inventory level basically remains unchanged year-over-year. So, that sets us up well going into 2021 to sort of continue the plan.

Yes. And that, I mean, the exact number it's a few pads.

So, whenever you think of five, six wells on a pad, seven holes on a pad, I think right now there's around three or so - three pads at any point in time. But there are less docks for us. They're just projects that are just part of the phased internal line. And as Chad said, we're like and I said in my comments earlier 2020 isn't an anomaly. So, we're basically drilling and completing a similar amount of feet. So, the working inventory will kind of remain consistent and it's really just working inventory not so much docks that are waiting for at home. It's just part of our natural cycle.

Our next question comes from Sameer Panjwani of Tudor, Pickering, Holt. Please go ahead.

Maybe just to stick on the topic of debt. Can you just walk us through how you think about appropriate leverage metrics in today's commodity price environment versus the 2.5 times ceiling that you previously talked about?

So, again, part of this probably is from day one being a little bit more articulate on this. So, this 2.5 leverage ratio is truly a ceiling. It's not a target. It's not where we feel like the business should be at all points of the commodity cycle. What it is, is just when we look at our longer range plans and we look at the strip and you sense the dialogues of it and you do scenario gaming, it just helps you have a - caught a consistent methodology as a warning sign that you don't want to be over it for extended periods of time. So it's not a target that we have had. It's not a target going forward. It's truly just a risk ceiling when we look at the long term here. I think as far as adjusting that ceiling, right now, again, it's a warning ceiling not a target we want to be at. When you look at, call it, more easily accessible debt capital markets and more favorable environments, you're comfortable with more debt whenever there's harder to access and higher cost debt, you want less debt. So where our comfort in is where we want to be. We'll change as times change, but definitely we want to ensure that we have a long healthy capital structure that works in downside scenarios, which is why we talk to things more broadly than just leverage ratio. I mean, it matters what your hedge book is. It matters how flexible your company is. It matters where you sit on the cost curve and what the quality your assets are. So the leverage ratio ceiling is really just a shorthand way we were trying to describe to the general public that there's things in place that we definitely want to avoid. But as far as where we sit totally on a capital structure, there's lots more pieces that we look at beyond that. And, again, as we've said with debt markets where they're at, logic tells you that you want to change the way you approach the debt of your business.

So would it be fair to say that at this point in the commodity cycle that maybe something closer to two times or less would be kind of a more appropriate way to think about what you think the appropriate leverage on the businesses for now?

Yes. I mean, again, short hand, it's hard to just pick one metric and say that this is it. So, depending on what the forward strip says, depending on where our liquidity is with the go-forward EBITDA, the trend to [indiscernible]. So, it's a wide range of things we look. We've historically been closer to 2 times than we have to 2.5 times, although with the commodity prices and some of that, it's picked up a little bit. So, net-net, we do feel that more - a stronger capital structure with less debt in a harder to get that environment is a better plan.

And then on the topic of drop-downs, can you help us understand how upstream cash flows would change if all the retained midstream assets were dropped? I think you've previously talked about in the ballpark of $200 million of retained midstream EBITDA. So, if all this was dropped down, would upstream EBITDA also drop by $200 million or is there another way to think about that?

Yes. And we haven't given a lot of this clarity since our 2018 March Analyst Day, so a lot of those numbers are from a different point in time and a different forward commodity strip, that strip macro environment and across the board. But the easiest way to think about it are - the midstream-only assets are one or two ways. So, the ones that are already in place and have flowing production on them and are capitalized and built out, it would be just trading upstream EBITDA for cash and the midstream company would get that EBITDA on a go-forward basis. Some of our areas still have capital to be spent. So, one way to think about it would be there would be offsetting future EBITDA that would go down from an upstream perspective, but the capital necessary to build some of these systems in our non-D&C buckets would go down on the front end as well. So, that kind of blends out and blends through. Then the last piece is the water side of the business and while the water side of the business is still, I'd say depending on what the commercial agreement would be between upstream and a midstream type company and the drop scenario. A lot of that cost from option perspective would be capitalized, since we do as Chad mentioned we use the vast majority of our water. So a lot of that would flow into the capital called it part for upstream and would be cash generation midstream. And we've talked historically that we do third party-type products in the water space as well and we've had years where we've had $10 million or so of third party-type income generated from that business.

Okay, that's definitely helpful walk through. Would it be possible to quantify any of the impacts in those three buckets at all right now, or is that something that you're saving for later time?

It depends on how you want to structure the commercial agreement. I think, if you have call it a normal type of a water contract, you could be somewhere in the $100 million in EBITDA type range. Again completely dependent on what you set your commercial rates to be coupled with the level of activity that you plan on doing over the next several years. So there's an order of magnitude that's kind of could be in the neighborhood.

And then, last question just on the asset level. As you guys were walking through a year of Southwest PA inventory, it looks like you are assuming 750-foot spacing. I think some of your peers have been widening out closer to 900-foot to 1,000-foot spacing. Did you have any plans to test wider spacing or are you comfortable with the 750?

We’ve gone through a series of spacing tests over the last several years. We've tried different offsets and tried different spacing. And at that point in time now, what we are settled at 750-foot, it's not just something we said and forget, we do continue to look at it in the context of changing gas prices. But where we're at in the gas price, we're all - and where we are in the price on the commodity deck, $750 million is still that sort of sweet spot number for us.

And one thing to note too, which I think is important, it depends on how you develop your field. So if you're developing your field efficiently and you have the laterals being completed in an orderly manner instead of jumping in and out areas and having interference with legacy production that you completed years ago, it’s a pretty material difference. So in situations, we are - when we are budding up against the edge of a well that's been there for a long time, we’ll be at further away than $750 million. But fortunately for us, a lot of our areas are pretty clean on the development front, so we're getting in there and doing it right, as opposed to having to come back and fight things that have already been drilled. And a big reason for that is, are held by production footprint. We didn't have to jump around and chase leases. A lot of our forward-thinking planning, we haven't had to keep a rig busy, so it's jumped around inefficiently. So laying it out from the front end and building the Midstream, the water, and just the sequence in order of how you develop the field makes a big difference on how you would think about the right spacing for the wells.

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

First on the Evolution all-electric frac. So I understand that they're saving money in terms of fuel. Is there anything negative or any downside in using those fracs and what is the planning going forward? I mean, if there - if it's pretty much all positive, is there a plan to use it as much as possible?

That is the go-forward plan. We’re seeing a lot of benefits from even beyond the cost savings. The way that the system is designed provided us a lot of operations flexibility with how we pump stages, with how much horsepower we’re able to deploy, what kind of rate we're going down hole with, provides a lot of flexibility beyond what you would get from a traditional conventional frac fleet. And so, because of those benefits, we are planning to use them as much as possible on a go-forward basis.

And no negatives in using them?

Well, it is a new fleet and new technology. There’s been a few sort of like conditioning sort of bumps on the road that we’re working through. But even with those conditioning bumps on the road, we're still completing more than our sort of expected number of stages a day. So, it's been really all positive even as we work through some of those initial sort of conditioning road bumps.

And then, back to the deck question, so Don, I think I heard correctly and I heard your follow-up explanation, so the 2022 is I think you said that you can pay off the majority of the notes with free cash flow. Now, of course, those are due in April 2022, so that would be free cash flow for the rest of 2019, full-year 2020, full-year 2021, and about a quarter of 2022. So, are you saying that when we sum all that up, that's basically greater than $450 million?

Yes. So, again, I'm not going to get into specific guidance numbers, but - so the math I did was just through the end of 2022. And I do think, as we talked about just cash flow from the business, there is plenty of different options and levers via small to medium asset sales, there is the drop conversations that we've discussed. There is the revolver, which we announced this morning, the borrowing base increased in spite of the lower commodities and all the other components around it. Our borrowing base increased from Q1 to Q3. We left that commitment one, but that product is only $600 million drawn, so there's space on the revolver and there's plenty of optionality on different cost to capital structures whether that selling assets or things that others have done and other project financing or components that exist out there. So the key for us is maintaining a bunch of ways to address these situations and starting early 2022. It’s still within 2022, there's lots of folks that have debt due before that, but we want to be disciplined, we want to be prudent and we want to ensure that we're out in front of it and in a manner that allows us to address it in many different ways.

And then in terms of –can you just describe like what part of the upside asset package would you be willing to sell?

Again, we’re one of the few E&P companies I think in Appalachia that sold undeveloped acres. We've sold PDPs. We've obviously - everybody's done things with midstream. And we have our water infrastructure, we have a ton of surface acres and stuff that are very valuable to people outside of E&P and inside the E&P. So, we look at these things mathematically. We try to be pretty - just call it transparent and follow the math on these types of situations and I think over the last several years you've seen us do that in many situations

And just in terms of this - I mean, I think it's a smart decision to focus on the debt obviously, but is that truly a rate of return decision or is that really kind of that you need to do it because it's coming due and you've got to protect the company and protect the balance sheet?

I think it's a rate of return decision because it really goes to what the cost to capital ends up being and that cost to capital effectively is our discount rate on what we think not just the debt or the assets but the entire company is worth.

And then a quick one, on the 2027 they’re trading at a pretty steep discount. Is that - you're just not going to worry about them for now and just kind of take the 2022s or are you thinking about some options for them as well?

Yes. Like it's always good to be thinking and looking at everything. I mean, the conditions are ever changing and quickly changing and very volatile. So, we look across all these different buckets. I mean, obviously, you want to ensure that the company and capital structure is strong from liquidity, from leverage, from interest rate costs. So, they're considered as part of the mix, but you want to make sure that you have the nearest term stuff situated properly as well.

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. I appreciate everyone taking the time to join us here this morning and we look forward to speaking with you next quarter.

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