Welcome to the CNX Resources first 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. Mr. Lewis, please go ahead.
Thanks, Anita. Good morning, everybody. Welcome to CNX's first quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; Don Rush, our Executive Vice President and Chief Financial Officer; Tim Dugan, our Chief Operating Officer; and Chad Griffith, our VP of Marketing and President of CNX Midstream. Today, we'll be discussing our first quarter results. 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, 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 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 Tim, and then Don. Then we will open the call up for Q&A, where Chad will participate as well. With that, let me turn the call over to you, Nick.
Thanks, Tyler. Good morning, everybody. I'm going to make most of my comments in reference to slide number three in our slide deck, which is an executive summary for the first quarter and looking forward to the path ahead. You'll see on that slide there's five main themes. They're all important. We're going to highlight each of those. Again, I'd like to spend my time covering those before we give it to Tim Dugan and Don for additional commentary. The first theme on slide three, we continued to execute, had another successful quarter of cost and margin performance. Those drove strong risk-adjusted returns across our entire portfolio. We hit production targets. More importantly, we hit the production targets while continuing to deliver exceptional cash costs and basin-leading all-in cash margins. We posted operating cash margins of 63%.
When you look to fully burdened cash margins, we posted them at 46%. Both of those are exceptional for any commodity business, including, of course, natural gas. As strong as those were, I'll tell you, too, that our expectation is to do better on costs as our activity set continues to benefit from low-cost Utica production and from economies of scale. The production, the cash costs that I just spoke about, our hedge book, all of those things delivered cash flows that allowed us to simultaneously grow at high rate of returns, to reduce our leverage ratio, and to reduce share count. Just like fourth quarter last year, being able to perform all three of these things in the first quarter this year, that's very powerful when you're looking at intrinsic value per share.
Let's start talking a little bit about the second theme on slide three, that is how we are adding in incremental activity to our prior discussed minimum activity set for 2019. The incremental activity add is driven by increased confidence in the rates of return that we see on our Utica opportunity set, it's the things that we highlighted in the earnings release. It's the Central Pennsylvania Utica data set, which continues to grow and continues to look good. We've got a good run going on drilling efficiencies in the Southwest PA Utica region. Of course, that's an important driver when it comes to what drill and complete cost ends up being. We're also refining our completion designs for the Utica in ways where we think that's also going to help on the drill and complete capital side of the equation.
Those operational developments, when you put them together with the robust 2020 hedge book that we put in place, it puts our risk-adjusted returns in a zone that warrant the incremental activity. Still emphasize that the most important thing we're looking for before jumping further into the Utica program is a decent production data set for Southwest PA Utica. That's going to, of course, help refine type curve, and we should start to see that data coming in the fall of this year. That'll substantially improve accuracy on capital allocation and rates of return, as we discussed on the last call. The growing confidence in the Utica, along with that low-cost structure and hedge book, it leads to the third theme on that slide, which is updating our 2019 capital guidance. Most of the net activity add, it comes from the Utica.
Our average incremental drill and complete capital is around $13 million per additional till. We'd like to also point out our investment in what we call other. That's a crucial contributor to maintaining and expanding our basin-leading margins into the future. That's our acreage bolt-ons on the land side. That's water infrastructure, which includes the line that we're building from the Ohio River, it's also, of course, midstream. On the midstream side, the all-important 2019 build-out for the STACK/Pay opportunity set, that's well on its way. In fact, it's slightly ahead of schedule from the last time we spoke. We're pulling spend that was projected for 2020 into 2019 to complete that midstream build-out sooner. That means significantly lower capital in midstream, both CNX attributed as well as CNX Midstream for 2020 when you compare it to 2019.
That also means substantial optionality for 2020 and beyond 2020 that'll be created by the completed midstream and water infrastructure build-out this year. Fourth thing on the slide really speaks to the results of the new 2019 capital and activity set. Now, of course, much of the capital spend associated with the additional activity that's going to take place in 2019, but the production benefit, it shows up in 2020. If you look at 2019 and you look at 2020 and assume our 2019 capital program, along with an additional $165 million of 2020 capital that'll be used to tie in line the DUCs left from the 2019 program, a few conclusions jump out at you. First conclusion, production for 2020 is going to be about 10% higher than the midpoint of 2019 production guidance.
Second conclusion at production, when you couple it with the cost structure and the hedge book, it'll generate substantial free cash flow. Now, that means free cash flow positive for 2019 and 2020 cumulatively, as well as about $500 million of free cash flow in 2020 only. All this assumes, by the way, the forward NYMEX and basis strips on our open volumes beyond the hedge book, not prices or some arbitrary price deck above the current strip. As to what we end up doing with that free cash flow, too early to tell, but I can give you some insight by thinking about the big three options. Of course, we could allocate the free cash to debt reduction and end 2020 at leverage ratios in the ones. We could invest in incremental activity and see cash flows in 2020 and beyond grow even more.
We could apply the free cash flow to share count reduction, keeping in mind $500 million represents 25%-30% of our current market cap today. The answer will likely be some combination of these three, obviously, we're excited about the opportunity to allocate the cash to optimize intrinsic per share value. Want to wrap up with comments on the last theme, that last row on the table in slide three. Speaks to not just the Shaw event, but more broadly on how CNX is methodically mitigating and reducing risk. Just a year and a half into the journey as a standalone E&P, CNX is now a top 10 natural gas producer in the U.S. When you think about it, we've only just scratched the surface with respect to the long-term upside of our company.
Depending on how timing of capital allocation plays out, wouldn't be surprised to see our ranking move up even further. With that opportunity comes a lot of responsibility, especially in an industry where extraordinary scrutiny is a fact of life. The imperative to live and breathe a core set of values, it's second to none in our list of priorities. We embrace it, constantly obsess over ways to minimize risks. In our business, just like in life, how you respond to the challenges really defines who you are. Last quarter, we had a challenge, and it presented itself to our team, and that, of course, was the Shaw 1G Utica Shale well in Westmoreland County, where we experienced a pressure anomaly during completions.
Following the successful remediation of the Shaw well and a comprehensive investigation, we believe the casing breach was caused by a confluence of a couple of things: environmental factors, pressures, and a material failure in the type of pipe that was used in the well. Shaw 1G is currently in the process of being permanently plugged. Four drilled but not yet completed wells, including three on the Shaw pad, contain the same casing as the Shaw 1G. The casing on those four wells will be isolated through the use of a liner, which effectively serves as an additional string of pipe before completion operations are commenced in order to ensure the integrity of pipe moving forward. As a precautionary measure on a forward-looking basis, we have ceased using such pipe across our operations where the identified combination of environmental factors and pressures could be present.
Per our updated guidance and subject, of course, to final DEP approval, we expect to complete the remaining Shaw wells on that pad in 2019. Responsibility, it's first on our list of values for a reason, and that's why we extended the investigation on the Shaw 1G well across our operations. We don't manage the company by the day, the week, or the quarter. We're focused on the long game, getting the generational opportunity right, and creating lasting value for all the stakeholders that we touch. Because of the comprehensive efforts, we've reduced our risk profile and enhanced our confidence in our Utica program. Those are obviously good things. With that, I'm going to turn things over now to Tim Dugan, and he's going to talk a little more in detail about our operations.
Thanks, Nick. Good morning, everyone. Looking at slide four, production in the first quarter was 133 BCFE, or a 3.5% increase over the same period last year. As expected, volumes declined modestly compared to the fourth quarter last year as the 2018 development program peaked late in the third quarter. Marcellus volumes increased almost 35% year-over-year as most of our development activity remains in the core Southwest P.A. Marcellus area. Utica volumes declined about 30% compared to last year because of the divestiture of our joint venture assets in the Ohio Wet Utica. Looking at costs, we continue to see strong quarterly production cash costs and cash margins of $1.11 and $1.86 per MCFE respectively. Fully burdened cash costs, which include production cash costs plus all other cash expenses, declined 6% compared to the first quarter of 2018, while full burden cash margin improved by 6%.
Also of note, Utica production cash costs were just $0.47 per MCFE in the quarter. Our cost performance continues to be driven by relentless attention to lease operating expenses and our advantage transportation, gathering, and compression profile compared to peers. We expect this cost advantage to become even more critical over the next couple years, facing a backwardated strip pricing environment. Looking at slide five, we turned in line 18 wells in the first quarter, all of which were in the Southwest P.A. Marcellus. At the end of the quarter, we are running five horizontal rigs, two in Southwest P.A. Marcellus, two in Southwest P.A. Utica, and one in the West Virginia Marcellus. As Nick mentioned, we did add some incremental activity to the prior minimum guidance, of which the majority is additional deep Utica wells.
At year-end 2019, we expect to have turned in line 62 wells and have started activity on an additional 24 wells that will turn in line in 2020. Those 86 wells compare to the 72 wells highlighted last quarter. One thing to point out, last quarter, we highlighted that we expected 12 Utica turn- in lines across 2019 and 2020, and we now have 18. The 12 Utica wells included a five-well pad in Monroe County that is now being deferred and replaced with Pennsylvania deep Utica wells. Our deep Utica well count is actually up by 11 wells out of the 14 well increase. This addition of deep dry Utica wells should highlight our continued excitement regarding the prospects for the Utica formation and its impact on the future of CNX development. Slide six highlights our 2019 development program and capital.
This is an update of what we provided last quarter. The main takeaway here is that we now expect to turn in line 86 wells across 2019 and 2020 combined for approximately $885 million in D&C capital, which includes approximately $15 million related to the Shaw event. This compares to the $700 million in D&C capital for 72 wells we highlighted last quarter. The table at the bottom of the page helps reconcile some of the plan changes. With this updated guidance, we're adding 11 deep dry Utica wells and eight Southwest PA Marcellus wells. We have deferred five Monroe County Utica wells, which were in the previous guidance. If you look at the summary table, it appears that we're only adding six Utica wells, but we are in fact adding 11 deep Utica wells.
Moving on to slide seven, let's look at some of the highlights from the core Southwest PA Marcellus area. As I mentioned, the majority of our activity has been in this piece of our portfolio, and specifically in the Morris and Richhill areas. Both fields have legacy wells that we're able to use as a comparison for our latest batch of activity. Across the board, we're seeing improved operational efficiencies and higher EURs. As an example, in Morris, our EURs have increased more than 110% from the legacy wells turned in line back in 2012 and 2013. In Richhill, EURs have increased by about 35% when compared to the much more recent legacy wells turned in line in 2015 and 2016. Most important, these new wells in both fields are flowing at or above our expected type curves.
A similar story can be seen on slide eight, where operational efficiencies and EURs have both improved in our Ohio dry Utica Switz field, where we have a couple of remaining pads left to develop. We expect to apply some of the recent lessons to the new locations. That includes optimized proportions of specialty sands, total sand per foot, and interlateral spacing. The other advantage of the Ohio dry Utica development program is that it has provided a range of insight that can be applied to the Southwest PA and CPA deep dry Utica programs. Data on optimal lateral spacing, sand loading, and specialty sand mixes are invaluable to the field and completion design schemes being implemented in Pennsylvania as we speak. On slide nine is the perfect pad concept that we first introduced at our Analyst Day in March of last year.
In the last 13 months, we've begun implementing several of the key elements of the perfect pad to drive capital efficiencies and improve EURs. For example, cellar technology for subsurface wellheads is being used on 11 pads where return trips are planned, which drives savings related to stack pay development. Our 3D seismic data set drives decision-making on where to place laterals, as well as how to execute the drill plan. The high-pressure, low-pressure two-pipe gathering system is under construction in the Richhill area, which will facilitate our full-scale stack pay blending strategy. Lastly, I'd add that we've updated our acreage by type curve area and net developed locations that ties to the figures released in our 2018 10-K.
The only major change from last year is that the Ohio wet Utica area has been divested as reflected on the map. These slides can be found in the appendix. With that, I'll turn it over to Don.
Thanks, Tim. Good morning, everyone. Slide 10 reflects some of the financial results of the quarter. Consolidated adjusted EBITDAX for the quarter was $268 million, or $1.37 per outstanding share. Standalone EBITDAX plus distributions in the quarter were $224 million, or $1.15 per outstanding share. Slide 11 highlights four important accomplishments in the quarter. First, our leverage ratio now sits at 2.1 times when looking at standalone net debt over trailing 12 months, standalone adjusted EBITDAX plus our CNXM distribution. Second, we further reduced our share count in the quarter. Since the inception of the program in the third quarter of 2017, we have bought back approximately 15% of the outstanding shares of the company. Third, we completed a $500 million senior notes offering to term out some of our debt, paying down our 2022 notes by $400 million and our revolver by $100 million.
Lastly, after the close of the quarter, as we announced today, we amended and extended our credit facility while reducing our rates by 25 basis points in the process. Now let's shift to our updated guidance. Slide 12 provides an overview of the major changes in guidance compared to last quarter. 2019 production volumes remain unchanged at 495 to 515 BCFE for the year. As you can see, we are adding incremental activity, and our D&C is up for both 2019 and the fleet over capital flowing into 2020. This incremental activity generates incremental rates of return and really sets us up for 2020 extremely well, as Nick stated earlier on the call. Our non-D&C increased slightly to $200 million due to a variety of investments that support the incremental activity. I will let CNX Midstream discuss their capital increase on their call following ours.
As everyone knows, we consolidate their results in our financials, which is why we are showing their capital of $310 million-$330 million on this slide. As for adjusted EBITDAX on both a standalone and consolidated basis, we essentially did a mark-to-market and saw these estimates come down due to a decline in natural gas prices since our last update. Slide 13 provides more detail on revenue and cost line items. As you can see, we now expect some modest improvements in SG&A and other operating expense this year. Slide 14 provides a couple of updates. To start, it shows our updated production forecast. At a high level, we expect 2019 production cadence to follow a similar pattern we observed last year, with volumes moderating through the second and third quarters and then increasing in the fourth quarter.
We expect our 2019 exit rate to be approximately 9% higher than 2018's. This program, as executed, would see rigs rolling off towards the end of the year, and we would end the year with three rigs running. Decisions to keep rigs or not will be made as the year unfolds based on a variety of factors, such as gas prices at the time of the decision and other capital allocation options. This slide illustrates what we are getting in 2020 for the incremental capital we are spending in 2019 and 2020. Assuming only this activity, we would expect 2020 volumes to grow by approximately 10%, which will position the company to generate over $500 million in free cash flow. The table on the slide walks you through a general buildup to show it.
As highlighted in our press release this morning, we expect to deploy that free cash flow across three options: incremental 2020 activity at high internal rates of return, debt reduction, and/or additional share buybacks. If history is any indicator, we will likely utilize all of these options. Another important factor I would like to point out on this slide is that we are using the current real forward strip for 2020, not a forward price assumption that is higher than the current strip. As you can see from the slide, most of our volumes in 2020 are de-risked through our hedging strategy. To put it simply, if the strip stays the same, we generate significant free cash flow as we have laid out on the slide. If gas prices get worse, we still generate significant free cash flow.
Of course, if gas prices end up higher than the current forward strip, we generate significant free cash flow. This reality is unique to CNX. Our strong hedge position can be found on slide 15. As you can see, we continue to programmatically layer on hedges and now have 440 BCFE of fully covered hedges for 2020. Slide 16 provides some additional color on our water assets and how water management is a competitive advantage for us. It is a great platform that reduces our lateral cost per foot, generates third-party cash flows, and has significant growth opportunities. CNX is at the forefront of fresh and produced water services. Our infrastructure is already moving third-party produced water and will move more as water becomes a bigger issue and topic across the industry.
I will conclude on slide 17, which is a reminder that we have a nice tax refund in 2019. Of which we received $36 million of the $146 million forecasted in the first quarter. With that, I'm going to hand it back over to Tyler.
Thanks, Don, and operator, if you can open the line up for Q&A at this time, please.
Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Our first question today comes from Wells Fitzpatrick with SunTrust. Please go ahead.
Hey, good morning.
Morning, Wells.
Morning.
You noted this in your prepared remarks that the decision to keep rigs and whatnot would be made at the time. Can you talk to the fact that 2020 is really just DUCs, and sort of what happens in 2021 if you execute on the program as described in the presentation and the press release. Would your corporate decline rate match almost the hedging profile that we see on page 15, or how do you think about that?
We did lay out our production wedges on 14. As you can, I guess, generally triangulate the 2021 volumes are in the zone of where our hedges are, as we've laid out our strategy of protecting the incremental investments with hedges to ensure that we are getting the risk-adjusted returns that we're expecting to get, and the gas price change won't affect it. As for what we do in 2020, we've tried to not get caught at a calendar year cutoff in 2019, so the bleed over capital to complete the work in progress is in there for 2020. What we do on top of that will be dependent on what gas prices and other things are in 2020.
As Nick said earlier, the balancing act of how much you put in each of the options we have to deploy the cash flow is really the decisions we'll be making in 2020 to ensure that 2021, and several years in front of that is a healthy business, a healthy capital structure. The most important piece is just ensuring you make incremental returns for incremental capital that you are spending.
No, that makes total sense. To try and back almost into more of sort of a run rate free cash flow yield. If on 2020 you exclude the ATM payment and you included the sort of drill costs on those 24 wells, again, almost as a theoretical way to look at capital efficiency, do you think the free cash flow, is it going to be somewhere in the, I'm coming to $300 million-$350 million. Is that about right?
Yeah. Obviously, one of the big factors is what the gas price is going to be in that year. What we've tried to very thoughtfully lay out is we're using the current forward strip. If you look, a lot of folks are using price points significantly higher than that current forward strip. If you're using those kinds of price levels, the free cash flows would be significantly more. Generally, I think you can triangulate to an area that you're in, looking at the way you described.
Okay. That's perfect. Just one more, if that's okay. Maybe I'm reading a little bit too much into it, but the great extra detail on slide 16, it kind of seems like some breadcrumbs that we could use to get to where the EBITDA might be on that system, which the natural inclination would then be to put the old MLP multiple on it. Are you guiding us in that direction, or is that really just sort of incremental detail for the sake of itself?
Yeah, I think some of this stems from our last call and conversations we've had since, just understanding some of this other spend and what it's for and what it does for the business. Water is a strength of CNX. It is something that we feel is not just a one-time, short-term investment. It is setting us up for very long capital-efficient development for several years, I think it's kind of hidden a little bit. We wanted to really highlight what that spend really gets you, the fact that it is a profitable business model that more and more folks, it's been topical here recently. We just wanted to let the investors know that we're ahead of the game in getting to a water model that not only works for CNX, but could work for the region and other third parties as well.
As far as how that business is set up and where it goes, lots of things to be figured out there. No guidance on that front, just the fact that it is a great asset, both for our company and potentially for generating incremental cash flows over and beyond that as we move forward.
Very helpful. Thank you so much.
The next question comes from Holly Stewart with Scotia Howard. Please go ahead.
Good morning, gentlemen. Maybe Nick, if you could talk a little bit about on slide three, which you sort of went through in detail, but you talk about an operational reevaluation. If you could just maybe share some thoughts on that process and the changes maybe to some of your best practices that you're doing differently, and maybe this ties into that casing liner that you mentioned. If you could talk about that as well.
Sure. There's really different components there of what we went through. There's with respect to the Shaw 1G itself and addressing that issue and then wrapping up the plugging operations on that, which should happen shortly. There was the second piece of this is the Utica wells in the current portfolio, 4 in particular, 3 of them on the Shaw well, that had utilized similar pipe, and making sure that we're beefing those up and removing any risk that we may see with respect to those by putting the liners into the vertical sections of those pipes. There's the QA/QC piece of just moving forward, all the ancillary benefits or improvements or refinements that we found, whether it's Marcellus or Utica, with respect to how we're going about drilling, completing, and producing those wells moving forward.
There have been a series of what I'd call tactical improvements that we've identified through this effort, and we extended it beyond the Shaw and frankly, beyond the Utica. Those are sort of the 3 big components of this, and it's the last one I think that's the most long-term and will impact our D&C and capital efficiencies the best. That's how I break them down. I don't know if Tim wants to add anything after the assets.
No. Just following up on what Nick said a little bit. We have revised some of our best practices, and primarily they're around our casing, everything from manufacturing through handling and installation. It's really just kind of fine-tuning what we already do. As with any improvement we find, we look at whether or not it applies to other areas of our operation. We've taken an in-depth look and made some modifications to some additions to best practices and also made some modifications to our casing design. We talk about continuous improvement, and this is really just part of it.
Okay, that's helpful. Maybe one for Chad on just the basis guidance. It looks like you're still guiding to $0.20-$0.25 after roughly $0.17 in 1Q. Anything just out there in Appalachia that you're seeing today on the basis market that's giving you the confidence that this sort of basis level continues going forward?
Yeah, I think a lot of it has to do with the expansion pipelines that have come online really over the last year, combined with really all of our peers slowing down. It's really set the stage for There's capacity to move gas out of the basin, so really basis is moving towards sort of variable cost to move that gas. So that's sort of what sustains that sort of That reaffirms that basis view for 2019.
Okay, that's helpful. Thanks, guys.
The next question comes from Joseph Allman with Baird. Please go ahead.
Thank you. Good morning, everybody. I've got a follow-up on the Shaw 1G. One of the factors you mentioned is environmental. Could you just elaborate on what you mean by environmental factors, and how do you know about those factors before you drill the well?
We did a pretty thorough review of the Shaw incident and brought in a lot of independent experts to help us out with that. Really majority of the data and information pointed to a material failure that was caused due to the high tensile strength pipe that was being used when exposed to certain environmental conditions. That pipe tends to become brittle and is more prone to environmental stress cracking. Some of the environmental conditions are certain temperature ranges, the presence of hydrogen that can lead to that. These findings, it wasn't just something that we came up with ourselves. We had independent experts working with us and confirming and providing thoughts and data to confirm what was being found.
Okay, that's great. Then just to confirm, it sounds as if you might use the same casing in certain circumstances, in other circumstances where the same environmental factors might exist, you're going to use different casing.
We have modified our casing program, going to a more, put it simply, a more ductile pipe that is not prone to embrittlement. There are areas that, like in our laterals, where the temperatures and the pressures are not an impact and the brittleness is not an issue, we may use some of this pipe. Overall, we've changed our casing design.
Okay, that's helpful. Then earlier in the call, you mentioned a different topic, the exit rate, 9% higher in 2019 versus 2018. Could you just confirm the exit rate? Does that mean 4Q over 4Q or December over December or December 31st over December 31st?
That's average December to average December.
Okay, that's helpful. Last one. Could you just make some comments, I know you're using the strip for your guidance. Talk about the gas macro, if you have any insights on the gas macro. You just touched on takeaways, so that was helpful. You mentioned water. What water issues are you or others experiencing? What water issues might you or others experience?
Yeah. Just first on the macro question. We're coming out of winter at really record low inventories and storage. Really the thing everyone's looking at this summer are going to be the injection rates, how quickly does the storage refill over 2019. That's going to be a huge factor of just how hot of a summer do we end up having. Really, I think it's 2019 and going into next winter and beyond, it's going to be largely a function of what weather looks like for this year and into winter. We've got a lot of incremental supply coming out of the Permian that's being matched with incremental LNG offtake and incremental demand going to Mexico. Sort of on a supply-demand balance, those two are sort of staying in sync.
I think this year's gas price going into next year's gas price really comes down to weather this year. We have a mild summer, we have a mild early winter, storage levels, I think we get back to sort of where we need to be on storage. If we end up with a super hot summer that keeps gas from being reinjected, then we might end up with a lower number entering winter. You might see some really strong prices again next winter. At the end of the day, I don't think any of us have a crystal ball to be able to predict that weather with a high level of confidence. That's why, as we talked about earlier on the call, we continue to programmatically hedge as we make incremental capital investments.
We hedge the gas, both NYMEX and basis, to take that commodity risk off the table.
That way we can continue to sort of shine through our capital efficiency and operational low OpEx.
On the water.
Yeah, go ahead. Just to follow up from Chad, we take the view that if gas prices get better, we can always add activity. If gas prices go down, you can't unspend the capital. We try to take a very thoughtful approach on making sure it works in the current strip, and not taking a risk both on the investment and the balance sheet health of the company if our gas prices don't turn out. If, like I mentioned earlier, a lot of folks are using a assumption for 2020 gas price, and if it holds great, we have lots of great things we can do. If the strip turns out to be true, or if gas prices go lower than the strip, our balance sheet, our capital structure, our leverage ratios are all still solid.
That's a unique position that we're in that a lot of others aren't if gas prices don't actually get healthier. As far as water, I'll generalize it really in two parts. You got the water supply side. That's obviously the Ohio River waterline and how we're approaching this. It's a consistent source of supply. If you look, and there's been wet seasons and dry seasons, but if you do run into a bit of a dry season, again, predicting weather, it's hard to do. There will be some pinch points on being able to adequately get supply for these fracks and the evolution crews that we establish and the rate of water you'll need, in barrels per day, barrels per minute to do the completion jobs that we want.
You need a strong supply source, and then that really helps de-risk and sets us up to take advantage of that side of the offense. Obviously, pumping water is much more efficient than trucking it as we've laid out on the slide. On the other side, the disposal end, it is sort of a tighter market on having adequate disposal capacity if fracs don't line up properly with flow backs and produce water volume. Whenever we look at our own business model and we set our plans, we've talked to ensuring that we have a healthy water balance, and we can be reusing the produced water that we have and paying very close attention to that. That is something that could, again, if it gets out of balance, which we've seen happen in a quarter or two, and everybody's heading to disposal, it gets very costly very quickly.
Those, the source side and the reuse side, are big items that could lead to margin producing opportunity going forward.
That's all very helpful. Thank you, guys.
The next question comes from Biju Perincheril with Susquehanna. Please go ahead.
Hi, good morning.
Good morning.
Question about 2020 or just the increase in activities this year. You mentioned the high confidence on the cost side in Utica. Can you talk a little bit more about your confidence level on the production side, especially in Southwest Pennsylvania? That's the area where it looks like some of the wells may not have been quite up to your expectations so far.
Sure. If you go to the incremental activity set that we've announced today above the minimum activity set we announced coming off the Q4 call. Most of that, as you said, is Utica-centric or Utica-driven. It's about the rate of returns as it's always been. The factors that have changed over the past couple of months with respect to our confidence in those rate of returns, you can sort of walk through the list. First on the hedge book, particularly '20 and '21, being able to take that revenue uncertainty off the table helps us obviously get more confident in the rate of return we're projecting for that incremental capital spend. When you start to get into the Utica-centric data, CPA, the Central Pennsylvania Utica footprint region, there the data set grew by another quarter, of course. Still looks good.
We've got yet another sort of time period of data to add to what was a pretty significant data set in Central Pennsylvania, which makes us more confident. On the drilling and completion side of things with respect to what it costs to basically turn and line a Utica well, we've also had some positive developments on that front the past couple of months. On the drilling side, we mentioned the drilling efficiencies, particularly in the Southwest Pennsylvania area of the Utica. That's an important piece of the equation for rate of return. With respect to the completion designs including Southwest PA Utica, or in particular with Southwest PA Utica, also some refinements where we feel that those designs will help drive drill and complete costs lower.
Those are sort of the factors that help give us more certainty or confidence in the rate of return with respect to Utica drill and complete capital. The last piece of the puzzle is the data for the Southwest PA Utica field, that's what's still waiting, coming up into end of summer, beginning of fall this year. Really at the end of the day, if you look at our activity set, it's those select wells that we're drilling and completing our pads that are going to provide the data, not just for ourselves, but frankly for the industry. That's why we basically peg the activity set at the level it's at now, let's assess, see where the data come in particular for Southwest PA, then refine, update our rate of return calculations and go from there.
To add to what Nick said, we have talked all along about the data set for the Utica, but also how compartmentalized the Utica is compared to the Marcellus
In Southwest P.A. is compartmentalized. When we talk about Southwest P.A. Utica, we're just not talking about one type curve, one set of characteristics. Talked about the geo hazards in Southwest P.A., the natural fracturing, and how challenging that can be, and that has certainly been a factor in some of the two data points that we have with our wells. But when you look at, Nick mentioned drilling efficiencies of the last four wells we've drilled in Southwest P.A., all four wells have been drilled in that 30-40 day range with two wells, one at 29 days, one at 31 days. Our drilling efficiencies have picked up tremendously. We've gained a lot of knowledge on our completion design, which is really helping us move towards that $12 million-$12.5 million well much quicker. We've gotten in more logs, more cores.
Seismic data has been critical in being able to place wells properly, so that we don't encounter the hazardous natural fracturing that can impact well quality. Keep in mind, Southwest P.A., when you look at CPA, we've had a lot of good results. We're much further along in the delineation process, and in some areas up there. In the Mamont area, we're really moving more into production mode. Southwest P.A. is still in delineation mode. Although there are some other data points from other operators, many of those data points are older. Older completion designs. There wasn't seismic data being used. You've got to take some of those older data points and use what you can, but they're not always completely representative, and we don't have access to all that data. We continue to build the data set.
We are still excited about the Utica, keep in mind, it is much more compartmentalized than the Marcellus, and there are some areas that are more challenged than others. As you can see from the increase in our activity, we are excited about the Utica. We think it is going to be a significant part of this company going forward, and we're going to keep pushing on.
Okay. That's very helpful. If I think about the incremental activity in Southwest P.A. Utica, would you say there's maybe a little bit more uncertainty or variability on the timing as you get the next batch of data points sort of proving up your thinking on the geology side?
The next two data points we get from a production standpoint, we've got a pad scheduled to turn in line in August and one in September. That production data will be significant and important. As we continue to drill wells, as I mentioned in my comments, we have two rigs drilling Southwest P.A. Utica right now. We've drilled one in northern West Virginia where we got logs and cores. We continue to build that data set of logs, cores, geologic data with the seismic alongside the cores and the logs. It builds our confidence and improves our understanding, and really each piece of data helps us understand and reduce our risk.
Great. That's helpful. The next question I had was on the three rigs you will have still on contract at the end of the year. What's the timing of when those three roll off contract?
The next one would roll off mid-year 2020. The others are beyond that. I don't know the exact dates, but they're beyond that. As with anything, we make those decisions, we're looking at the market and all the conditions, the hedging and price environment and our drilling efficiencies, and we make those decisions. We'll address that. We've got time frames set, understanding when those rigs come up. We'll make sure those questions are answered and addressed in the proper time frame.
Perfect. Thank you.
The next question comes from Jane Trancenko with Stifel. Please go ahead.
Good morning. My first question is on the 2019 CapEx increase. I'm trying to understand if it's mostly attributable to this additional activity that you guys highlighted, 14 additional D&C in 2019 and 2020, or if there are other factors that impact 2019 CapEx.
Sure. There's obviously different pieces of the build up to capital, we've sort of laid those out in the release and the slide deck. Certainly the incremental activity of the 14 D&C are a big incremental piece of that, we tried to itemize that. We've also shown what the changes were in the other category, which again is our land capital, our water infrastructure, and our midstream side, as well as CNX Midstream's capital because of the acceleration of originally projected 2020 activity now that we can get done in 2019. If you're looking at things on a consolidated basis, that's another driver. Those are laid out in some detail, but the biggest piece of that is the incremental activity set above the minimum guidance that we discussed on the Q4 call for 2018.
That's very helpful. Could you maybe explain why exactly you decided to add incremental activity in 2019 to kind of deliver higher production growth in 2020? What was the motivation for doing that?
Sure. This goes back again to the rate of returns driving our decision-making. When we looked at the incremental activity, whether it's the capital or the production that would come from the capital investment, we're ultimately looking at the rate of returns and letting the rest of those metrics become more results versus what we're solving for. We are solving for rate of returns and the risk associated with those rate of returns. When we look at our hedge book, particularly for 2020 and 2021, which will be a big determinant. The revenue in the front two years of a shale well is going to be a big determinant of the ultimate rate of return just because of the well profile.
Being able to take that uncertainty off the table and knowing for certain with the hedge book what the realizations will be, that gave us confidence in rate of returns. We didn't say much on this call, actually, but we've talked about in the past quite a bit about the Marcellus, and we've done some updating of performance metrics in the Marcellus, and certainly it continues to perform and frankly, outperform. With respect to well profiles in the Marcellus, and then we talked through on some earlier questions about the confidence that we're growing with the well profile in the CPA Utica. Our drilling complete costs in the Utica, because of the drilling efficiencies we've recently seen in Southwest PA and our completion designs that we refined with respect to Central Pennsylvania and Southwest Pennsylvania Utica.
You add all of those together, basically the rate of return that we see coupled with the risk or the uncertainty tied to it, put us in a position where we believe it's prudent to invest in that capital if we're solving for intrinsic per-share value.
Okay, got it. May I ask the last question? I'm trying to understand the medium-term production outlook. Production outlook beyond 2021. I understand that you guys do not target free cash flow necessarily. It seems to me that leverage should be the guiding factor, and maybe you can remind us the leverage band that you would like it to stay within over the medium-term, long-term.
Yeah. We've talked to this 2.5x leverage ceiling is the way we think about the balance sheet. We've also said, it is not just leverage ratio in isolation. We view our hedges part and parcel to our capital structure and our balance sheet, likewise, our low fixed cost obligations and low cost structure and asset qualities that we do have. We do look as we laid out in here, 2.1 is our current trailing 12 months leverage ratio. We like to look out one year, two years, three years, really, we want several years of dependable, reliable cash generated from the business when we're setting our capital structure.
We do look at it sensitizing for gas prices both up and down, and our hedge book really is what gives us the ability to set these targets and have clarity one, two years down the road where most folks don't, if you don't have a hedge book to kind of protect the revenue side of your business.
Okay, got it. Thank you so much.
This concludes our question and answer session. I would like to now turn the conference back over to Tyler Lewis for any closing remarks.
Great. Thanks, Anita, and thank you everyone for taking the time to join us this morning. We look forward to speaking with you next quarter. Thank you.
This conference has now concluded. Thank you for attending today's presentation. You may now disconnect.