Good day. Welcome to the CNX Resources third quarter 2019 earnings conference call. All participants will be in listen only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press Star, then one on your telephone keypad. To withdraw your question, please press Star, then two. 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 to everybody. Welcome to CNX third quarter conference call. We have in the room today Nick DeIuliis, our President and Chief Executive Officer, 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, CNX consolidates its results, which includes 100% of the results from CNX Gathering LLC, and CNX Midstream Partners LP. Earlier this morning, CNX Midstream Partners, ticker CNXM, issued a separate press release. 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 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 in 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. First, I want to talk about our inventory and our base plan. Let's talk about what we designate as our Tier 1 core inventory. That's shown and summarized on slide four. I'll be speaking from slide four 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.
Focusing in on the core Southwest Pennsylvania central type curve region, you can see we've got approximately 70,000 net undeveloped acres. Using an average lateral length 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. Assuming a consistent go-forward development program, you'd have enough drilling locations to support 12 years worth of drilling.
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 land capital. Another active area in our development plan is the Shirley-Pennsboro location and 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. As you can see on slide four, due to the prolific nature of our inventory, 40 wells a year actually grows our production. 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 base plan has been reviewed, I want 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 to the program over the next decade as gas prices warrant it, and/or B, add substantial inventory for years 2013 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. In the meantime, we will continue to do a couple of wells a year to facilitate our blending strategy while further refining the cost and reservoir characteristics.
Another area, 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. 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. 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 cost, and that's really, I think, highlighted best on slide five. Slide five 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. 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 and 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. 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 six 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.
As the slide shows, slide number 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 to right on that slide. Let's talk about hedging on slide seven. 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. For 2021, we're approximately 76% hedged. That's based on the consensus numbers. We'd be even more hedged if you assume flat production.
This hedge book was built to protect our returns. It was built to protect our capital structure, it allows us to stay strong in the downturns and grow in the upturns. Our hedge book continues to be unrivaled, 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. Let's talk about free cash flow. That's on slide eight. Despite the macro environment, gas prices, and NGL prices getting worse since our last update, CNX improved our free cash flow projections for 2020, we also added cash flow to 2019 as well. 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. In general, I'll tell you, we were 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. Even with the lower activity levels, we increased our 2019 production guidance, and we're still projecting to grow our volumes in 2020. Combination of increasing our already positive free cash flow in 2020 while still growing production, that is certainly unique among the sector. In summary and wrapping things up, looking at slide nine, 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. These advantages, they allow us to approach a lower priced commodity cycle from a position of strength. Even though gas prices got weaker this quarter, CNX Resources just got stronger. These advantages and the unique philosophy that we deploy, they continue to separate us from our peers and we're positioned very well for whatever lies ahead. 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 Mcfe or a 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 into specifics on well performance for these recent wells, it looks like pressures were 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 as the foundation of our steady-state go-forward plan, which will include a couple 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 a 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 is our Ohio River waterline, which was completed this quarter 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 in 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. 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 of return.
That said, dollar per foot is an important metric that contributes to rates of return. There are many ways in which we could further reduce our D&C per foot number, but some of those ways could create problems down the road and lead to impaired rates of return on that investment opportunity. Nevertheless, with the math and engineering supported, 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 five-well pad at an all-in $640 per lateral foot, inclusive of capital, beginning with groundbreaking through turn and line. Just to sum it up, the team continues to execute and is constantly pushing for more efficiencies and cost reductions. 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. 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 burdened 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. 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. You are seeing that plan in action now. Just to be clear, we have not only positioned the business to do well in a downside case, we have also created a lot of flexibility. To accelerate activity if 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. 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 this slide, so I will 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. 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. 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 those 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.
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 535-565 Bcfe guidance when compared to the previous update of 570-595 Bcfe. 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 2020 to 2021 and beyond path easier, saving some locations for later, having less wells declining in 2021 and beyond. 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 2022 to pay off the majority of our outstanding 2022 notes using our own free cash flow from the business. Remember, we are using the current forward strip for our forecast. 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. 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 wells, 35 in the Marcellus and 12 in the Utica. To be specific, the breakdown of the 12 Utica wells is as followed: 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. 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% hedged. With our new plan, our cash flow is even more protected. With the $0.10 move in 2020 gas prices only resulting in a $5 million change to our standalone adjusted EBITDA+ distributions amount. 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.
As you can see on slides 23 and 24, our balance sheet is looking stronger and stronger versus our peer group in this challenging price environment. CNX's leverage profile screens very well compared to our peers, especially when including off-balance sheet obligations such as FT, which the slides 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. 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 any environment. With that, I'm going to hand it back over to Tyler.
Thanks, Don. Nicole, can you please open the line up for Q&A at this time?
Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up the handset before pressing the keys. To withdraw your question, please press star then two. Our first question comes from Welles Fitzpatrick of SunTrust. Please go ahead.
Hey, good morning, and congrats on the strong guide there. I think I know the answer here, but does a modestly slower 2020 plan, does that change any of the theoretical drop cadence in y'all's minds?
Yeah. We haven't given any guidance on what drop cadence would look like. We have found it important to not need those in our go-forward plans from the upstream perspective, and as well as the midstream perspective for that matter. Obviously, as inventory lasts longer and different areas get pushed back, the need to build infrastructure in some of the new areas isn't as pressing at the moment. In general, we'll figure these out as time requires, but we got time, and both companies have the wherewithal to do it when it makes sense for both.
Okay. You guys mentioned a couple of times in the prepared remarks about your ability to add rigs quickly if prices improve. 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 always comes back to rate of return. We compare the rate of return from the incremental drilling activity to the other opportunities we have for capital allocation. 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 of return end up being when you compare D&C capital versus whether it's share buybacks, debt reduction, or other uses of capital.
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 what the gas price change looks like. Is it just a quarterly change or is it a forward strip modification? Do we have the ability to hedge in to lock in some of those additional cash flow streams?
Okay. Perfect. Then just one last one for me. 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 diffs and volatility at Dom South and M2, and how you think that might shape up throughout the end of the year in 2020?
Sure. I think a lot of the volatility in the local market, there were some pipeline interruptions during the quarter, particularly getting gas to the Gulf. I think that directly led to a lot of the volatility you saw in the local markets here in Appalachia. We've been largely protected from that through our extensive basis hedging program. We've largely been isolated from that when you look at sort of an all-in, including hedge realizations. I think a lot of the volatility's been driven by the uncertainty of timing of getting those interruptions corrected, and what are the flows going to be, and when are we going to get that stuff online. As different producers and market participants figure out ways to navigate around those transportation constraints. It just sort of led to a really volatile Q3.
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 of 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 leading towards a sort of tight winter, and I think we're all hoping for a cold winter. That storage balance and some of the transportation constraints caused by that pipeline interruption just caused, I think, a lot of market volatility.
Okay. Very helpful. I appreciate it. Thank you.
Our next question comes from Leo Mariani of KeyBank. Please go ahead.
Hey, guys. Just wanted to 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 what happened there, if you guys were able to get away from one of those contracts, and what are the costs associated with that?
Sure. Thanks for the question. We gained some really good efficiency towards the turn of 2019. We were able to do more with less. When we look at the macro environment, the natural gas price environment, and how much we were getting out of the rigs we had, we didn't need that third rig to necessarily hit the targets that we had already set out there. We began thinking, "Okay, well, how do we restructure this?" Or, "What can we do to bring our activity set back in line now that we've gotten more efficient?" We were able to do some restructuring, and we were able to offload that third rig a little bit earlier than previously expected, really a cost-neutral basis.
Okay. That's helpful for sure. I guess in your prepared comments, you talked a little 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 later in the year. Is that just a function of you having more second half tilts in 2020 like you had in 2019? Is that how we should think about it? I just want to make sure I heard that right.
That's a good way of looking at it. You can look at Slide 20 for a visual depiction of what the production cadence will look like in 2020.
Okay. That's helpful. I guess any update on Utica well costs? Obviously, you guys have done a good job driving those down over the last year. Just want to get a sense of where those are today and where do you think those may go into 2020.
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 that completion design, on those production facility designs? Really challenging the team to look at every piece of that to make sure it's optimal from a rate of return perspective. We've already announced the Majorsville 6 results prior quarter. Those were very nice with three of those four wells in the $12 million range, and the fourth well at $15 million. Again, that higher cost on that fourth well is really due to some science work that we've done on that well. The other Southwest PA Utica pad we brought online this quarter, the Morse 10. It was a little bit higher in cost.
I don't think we're going to disclose the exact number on that. It was a little bit higher. 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 was this pad. We installed those liners. It drove up higher costs.
Okay. That's very helpful. I guess, just lastly on the comments you made in the press release. It sounds like there's going to be a little bit more of a focus on debt paydown versus stock buyback. Could you maybe talk to that a little bit? I think, Don, you'd mentioned that a lot of it had to do with the existing debt market conditions. Just provide a little more color around that.
Yeah. 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 into the drill bits or bolt-on land acquisitions, whether we use it for buybacks or whether we use it for the balance sheet, aka debt reduction. We try to be thoughtful and disciplined and prudent. We take the long view on these types of items, and obviously, the debt markets have changed really quickly over the course of the year and really over the last few months, even more so. Common sense tells you, a big part of the NAV per share intrinsic value of the business is the cost of capital and the risk associated with it.
In today's environment where the credit markets sit, the prudent, disciplined thing to do is just make sure that your capital structure is strong and solid. The hedge book and everything we've built keeps it strong and solid. As you peer into the future, I think everybody has learned here over the last decade, it's impossible to predict the future. We don't try to. We try to just ensure that the business survives, works, is healthy, and is growing per share value over the long haul, step by step along the way. 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.
Okay. Thank you.
Our next question comes from Holly Stewart of Scotia Howard Weil . Please go ahead.
Good morning, gentlemen. 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. 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.
Yeah. 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 of debt we could retire, all of them, as Don sort of lined up in the prior question, have some pretty compelling rates of return tied to them using the current 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. We will continue to run the rate of return metrics.
A key point in what to do with respect to future capital allocation, 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 multi-years that we can hedge and effectively lock the rate of return in on, or is this 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 or valued at today.
I can tell you that when you start to think about the risk and frankly, what we know or don't know about those versus what we know across those three 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.
That makes sense. Thank you. Don, you made a comment there at the end that I was just trying to understand. I think you said the majority of your 2022 maturity, which we thought was something north of $875 million, would be paid off with free cash flow. Do we get that right? Maybe could you just help us understand that comment?
Yeah. If you look, the way I tried to characterize it was we did give free cash flow guidance for 2020. We also laid out what a maintenance capital program all in would cost to hold that type of production level through several years. Back to the envelope, I think you can 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. In that math, you quickly get to call it significantly more than half of the 2022s being able to be paid down from cash from the business. When you add into 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 year-over-year as well. To help frame the cash flow projections and how we think about the risk associated with the 2022s and managing them in multiple ways instead of only having one option over our disposals is what we're trying to set up.
Okay. Just to make sure I understand. You're saying if you went in 2020 through 2022 at a maintenance capital program, the free cash flow generation that that would throw off would cover the repurchase of the majority of that note?
Yeah. Like I said, we wouldn't want to get into 2021 and 2022 guidance at this point. With the maintenance capital, and the hedge book that we have, and the line of sight on cash flows, we feel good that the majority of the 2022s could be handled with cash from the business. In the meantime, we still are always looking at every option to manage our capital structure of the company. Just wanted to provide a little bit of color without getting into specific guidance.
Yep. That's helpful. Then maybe, Chad, I think you pointed to slide 20 for sort of the production cadence as we moved 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.
Okay, great. Then just maybe one final one for me. Can y'all give an expected DUC count at year-end 2019 and 2020?
Oh, man. I'm sorry, Holly. I jot those numbers down earlier. 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 the roughly two rigs and a frack crew or so, we are basically staying in pace. The amount of working inventory we end 2019 with, we complete some of that inventory in 2020, and we've replaced that duck inventory with drilling activity in 2020. 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. That sets us up well going into 2021, just where we continue to plan.
Yeah. The exact number, it's a few pads.
Yeah.
Whenever you think of five, six wells on a pad, seven wells on a pad, I think right now there's around three or so, three pads at any point in time. They're less DUCs for us. They're just projects that are just in part of the phase to turn online. As Chad said, and I said in my comments earlier, 2020 isn't an anomaly. We're basically drilling and completing a similar amount of feet. The working inventory will kind of remain consistent, and it's really just working inventory, not so much DUCs that are waiting for a home. It's just part of our natural cycle.
Got it. Appreciate it. Thanks, guys.
Our next question comes from Sameer Panjwani of Tudor, Pickering, Holt. Please go ahead.
Hey, guys. Good morning. 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 this 2.5x ceiling that you previously talked about?
Yeah. Again, part of this probably is from day one being a little bit more articulate on this. 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 at all points of the commodity cycle. What it is just when we look at our longer range plans, and we look at the strip, and you sensitize what's off of it, and you do scenario gaming, it just helps you have a, call it a consistent methodology as a warning sign that you don't want to be over it for extended periods of time. 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 where 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. Where our comfort is where we want to be will change as times change. 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. 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 of your assets are.
The leverage ratio ceiling is really just a shorthand way we are trying to describe to the general public that there's things in place that we definitely want to avoid. As far as where we sit totally on a capital structure, there's lots of more pieces that we look at beyond that. 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.
Okay. 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 a more appropriate way to think about what you think the appropriate leverage on the business is for now?
Yes. Again, shorthand, it's hard to just pick one metric and say that this is it. Depending on what the forward strip says, depending on where our liquidity is with the go-forward EBITDA, the trailing 12 months. It's a wide range of things we look at. We've historically been closer to two than we have to two and a half, although, with the commodity prices and some of that, it's ticked up a little bit. Net-net, we do feel that a stronger capital structure, less debt in a harder to get that environment is a better plan.
Okay. Makes sense. 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 the ballpark of $200 million of retained midstream EBITDA. If all this was dropped down, would upstream EBITDA also drop by $200, or is there another way to think about that?
Yeah. We haven't given a lot of this clarity since our 2018 March Analyst Day. A lot of those numbers are from a different point in time, in a different forward commodity strip, debt strip, macro environment, kind of across the board. The easiest way to think about it are the midstream only assets are one of two ways. 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. One way to think about it would be there would be offsetting future EBITDA that would go down from an upstream perspective.
The capital necessary to build some of these systems in our non-D&C buckets would go down on the front end as well. That kind of blends out and blends through. The last piece is the water side of the business. 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 in a drop scenario, a lot of that cost from upstream perspective would be capitalized since we do, as Chad mentioned, reuse the vast majority of our water. A lot of that would flow into the capital part for upstream, and would be cash generation for midstream.
We've talked historically that we do third-party type products in the water space as well, and we have had years where we've had $10 million or so of third-party type income generated from that business.
That's definitely a helpful walkthrough. Would it be possible to quantify any of the impacts from those three buckets at all right now, or is that something that you're saving for a 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 $50 million-$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. As an order of magnitude, that kind of could be in the neighborhood.
Okay. Last question, just on the asset level. As you guys were walking through your Southwest PA inventory, looks like you were assuming 750-foot spacing. I think some of your peers have been widening out closer to 900-foot to 1,000-foot spacing. Do 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. We've tried different spacing. At this point in time now, we are settled at 750. It's not just something we set and forget it. We do continue to look at it in the context of changing gas prices. Where we're at in the gas price world and where we are on the price on the commodity stack, 750 is still that sort of sweet spot number for us.
One thing to note, too, which I think is important. It depends on how you develop your field. If you're developing your field efficiently and you have the laterals being completed in an orderly manner, instead of jumping in and out of areas and having interference with legacy production that you completed years ago, it's a pretty material difference. In situations we are butting up against the edge of a well that's been there for a long time, we'll be it further with 750. Fortunately for us, a lot of our areas are pretty clean on the development front. We're getting in there and doing it right, as opposed to having to come back and fight things that have already been drilled. A big reason for that is our 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. Laying it out from the front end and building the midstream, the water, and just the sequence and order of how you develop the field makes a big difference on how you would think about the right spacing for the wells.
Okay, great. Thanks, guys.
Our next question comes from Joseph Allman of Baird. Please go ahead.
Thank you. First on the Evolution all-electric fracs. I understand that they're saving money in terms of fuel. Is there anything negative or any downside in using those fracs? What's the plan going forward? If it's pretty much all positive, is the plan to use it as much as possible?
That is the go-forward plan. We're seeing a lot of benefits from it, even beyond the cost savings. The way that the system is designed provides us a lot of operational 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. Because of those benefits, we are planning to use them as much as possible on a go-forward basis.
Got you. No negatives in using them?
Well, it is a new fleet, a new technology. There's been a few commissioning bumps in the road that we're working through. Even with those commissioning bumps in the road, we're still completing more than our expected number of stages a day. It's been really all positive, even as we work through some of those initial commissioning road bumps.
Very helpful. Back to the debt question. Don, I think I heard correctly, and I heard your follow-up explanation. The 2022s, I think you said that you can pay off the majority of the notes with free cash flow. Those are due in April 2022, that would be free cash flow for the rest of 2019, full year 2020, full year 2021, and about a quarter of 2022. Are you saying that when we sum all that up, that's basically greater than $450 million?
Again, I'm not going to get into specific guidance numbers, but the math I did was just through the end of 2022. I do think, as we talked about, just cash flow from the business, there's plenty of different options and levers via small to medium asset sales. There's 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 $2.1 to $2.3. We left a commitment to do one, that product is only $600 million drawn, there's space on the revolver. There's plenty of optionality on different cost of capital structures, whether that's selling assets or things that others have done, and other project financing or components that exist out there.
The key for us is maintaining a bunch of ways to address these situations and starting early. In 2022, there's lots of folks that have debt due before that. We want to be disciplined, we want to be prudent, we want to ensure that we're out in front of it in a manner that allows us to address it in many different ways.
Got you. In terms of, can you just describe what part of the upside asset package would you be willing to sell?
We're one of the few E&P companies, I think, in Appalachia that sold undeveloped acres. We've sold PDPs. Obviously, everybody's done things with midstream. 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 of E&P. We look at these things mathematically. We try to be pretty, just call it transparent, and follow the math on these types of situations. I think over the last several years, you've seen us do that in many situations.
Got you. I think it's a smart decision to focus on the debt, obviously. Is that truly a rate of return decision, or is that really kind of, you need to do it because it's coming due, and you 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 of capital ends up being, and that cost of capital effectively is our discount rate on what we think, not just the debt or the assets, but the entire company is worth.
Got it. Quick one. The 2027s are trading at a pretty steep discount. Is that you're just not going to worry about them for now and just take care of the 2022s? Or are you thinking about some options for them as well?
Yeah, look, it's always good to be thinking and looking at everything. The conditions are ever-changing and quickly changing and very volatile. We look across all these different buckets. Obviously, you want to ensure that the company capital structure is strong from liquidity, from leverage, from interest rate costs. They're considered as a part of the mix, but you want to make sure that you have the nearest term stuff situated properly as well.
Got it. Thank you very much.
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.