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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning and welcome to the CNX Resources Second Quarter 2018 Earnings Conference Call. All participants will be in listen-only mode. Please note, this event is being recorded.
I would now like to turn the conference over to Tyler Lewis, Vice President of Investor Relations. Please go ahead.
Thanks, Andrew, and good morning, everybody. Welcome to CNX's second quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; Don Rush, our Executive Vice President and Chief Financial Officer; and Tim Dugan, our Chief Operating Officer. Today, we will be discussing our second quarter results, and we posted an updated slide presentation to our website.
To remind everyone, CNX consolidate its results, which includes 100% of the results from CNX, CNX Gathering LLC and CNX Midstream Partners LP on a consolidated basis. Earlier this morning, CNX Midstream Partners, ticker CNXM, issued a separate press release. And as a reminder, they will have an earnings call at 11:00 AM Eastern today, which will require us to end our call no later than 10:50 AM. The dial-in number CNXM call is 1-888-349-0097.
As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risks, which we've laid out for you in our press release today as well as in our previous Securities and Exchange Commission filings.
We will begin our call today with prepared remarks by Nick, followed by Don and then Tim, and then we will open up the call for Q&A.
With that, let me turn the call over to you, Nick.
Thanks, Tyler. Good morning, everybody. I want to jump right in and review some of the highlights of the quarter that we've summarized on slide 3 of our presentation. We recently announced an agreement to sell our Ohio Utica acres associated with our joint venture with Hess for approximately $400 million net to us.
Once closed, this transaction will bring our 2018 total asset sale proceeds to over $750 million. The sale is another example of an intense focus on capital allocation, and we took an asset with no planned future activity, and we pulled forward that value. Even though these assets are good, they couldn't compete with the higher economic opportunities that we've got within our portfolio.
Also in the quarter, we repurchased $300 million of our 8% 2023 notes using our credit facility, which results in a nice decrease in our future interest expense and a corresponding boost to our future cash flows. In addition to repurchasing our notes, we've also continued to opportunistically and consistently buy back our shares. I'll have more to say on that in a minute.
You shift over to production, as we guided to last quarter, we expected a decline in the second quarter compared to our first quarter. That's exactly what happened. We turned in line only three wells. Plus, this was the first quarter with our shallow oil and gas assets not in our production mix since that transaction closed at the end of the first quarter. Tim Dugan is going to talk more about the cadence for the rest of the year as well as some of the exciting Utica results that we're seeing with the deep dry Utica delineation.
We also had some financial guidance changes this quarter. We reaffirmed 2018 production, but we increased our 2018 EBITDAX guidance range to $835 million to $860 million. That compares to the previous guidance range of $810 million to $835 million.
Even though we had some significantly lower unit costs in second quarter versus first, we experienced some cost increases that resulted in us increasing our cost guidance for the year as highlighted on slide 9. We had higher gas prices helping to more than offset this, and that's what led to the raise in the EBITDAX guidance that I just mentioned. We also increased our 2018 capital guidance range to $900 million to $950 million. That's compared to our previous guidance range of $790 million to $915 million.
Don Rush and Tim, they'll go into the details, but it's important to note we continue to make all capital allocation decisions on a strict rate-of-return basis, while looking for opportunities to increase efficiencies. Also want to mention that we continue to see positive results in our Utica delineation program. Our Richhill 11E well continues to flow above type curve and we're continuing to learn a lot in this area and are applying what we learn to future Southwest PA deep dry Utica wells.
Slide 4 summarizes the sale of the Ohio joint venture asset that I just touched upon a minute ago. Transaction includes the sale of approximately 26,000 net undeveloped acres and 50 producing wells for expected gross proceeds of approximately $800 million, again, which our share will be $400 million. We continue to evaluate the use of proceeds. Those are to pay down debt, repurchase more shares, put towards drilling and completion activity, and/or take advantage of bolt-on acreage opportunities. And we expect the transaction to close during the third quarter.
Slide 5, I think, is an important slide and it provides a nice overview for some of our capital allocation decisions. As I mentioned during the quarter, we bought back $300 million of our 8% 2023 notes that results in net interest savings of approximately $14 million a year for the next five years. Our leverage for the quarter, assuming our new 2018 EBITDAX guidance, is 2.4 times. And if you pro forma our leverage for the Utica sale, it drops to 2 times which, of course, is well below our prior stated 2.5 times leverage ratio target.
The right-hand slide – I'm sorry, the right-hand side of slide 5 shows that we've been repurchasing our shares since October of last year, and we've been doing that consistently for each quarter since. We repurchased 5.3 million shares through July 2017. That brings our total to 17.9 million shares bought back since the inception of the program. In total, we've reduced 8% of our shares outstanding. So, if there are questions on whether you should consider reducing CNX's future share count in your models, I think it would be a mistake to not do that. We said that at our Analyst Day back in March, and I just wanted to reiterate that today.
If we were to do nothing with the $400 million cash proceeds from the Utica sale, our leverage is going to be at 2 times. We've got the opportunity to use our balance sheet capacity up to the 2.5 times target, like we've discussed. So if that 2.5 times leverage ratio is in fact the leverage target you're assuming, don't forget to change your denominator because we're going to put that capacity to good use.
In summary, I think it's important to note that there is a big difference in what we can afford to do versus what we will actually do. So for a capital allocation firm and a commodity business, what we can afford to do is not the end-all. Yes, we can afford to use our balance sheet capacity up to 2.5 times target that I just mentioned on spend. Yes, we can afford to take our time, and yes, we can enjoy solid returns at our current cost structure.
But we aren't going to be content with any of that. Instead, what we're going to do is different, but yet it's very simple. We're going to drive efficiencies further, costs lower, and productivity higher. Ultimately, what we're going to do is relentlessly obsess on controlling the controllables and continually improving.
And with that, now I'm going to turn the call over to Don who's going to discuss our financial results.
Thanks, Nick, and good morning, everyone. I would like to start out by reviewing our quarterly results, which are highlighted on slide 6. In the second quarter, we had adjusted net income attributable to CNX shareholders of $42 million or $0.19 per diluted share and adjusted EBITDAX attributable to CNX shareholders of approximately $204 million, an outstanding 133% increase from the year earlier quarter. And as we have been saying for quite a while now, this rapid EBITDAX growth is driving our leverage ratio down quickly.
As Nick already mentioned, we're on track to be significantly lower than our 2.5 times target by year-end once we include the expected proceeds from the Ohio JV transaction. And to expand on that point for a minute, the way we think about use of proceeds from the Hess deal is that day one the proceeds are used to pay down our credit facility or other debt based on the way we have structured our balance sheet and our revolver usage, that in turn creates balance sheet capacity for us to use for the options Nick has already laid out. And if you remember, we were asked at our Analyst Day why we upsized our credit facility. And the reason is to have the balance sheet flexibility to approach decisions this way.
So in summary, we did what we said we were going to do this year and we actually achieved it faster than we forecasted. And now that we are there and have incremental capacity, we have the optionality to use the capacity if and when we see fit.
Next, I would like to point out that our press release, again, and earnings slides clearly provide the definitions for attributable and consolidated numbers to ensure proper understanding. You may recall that last quarter I recommended analysts submit EBITDAX estimates on an attributable basis and not a fully consolidated basis so that figures are most comparable to guidance and other estimates. We have found that the majority, but not all have chosen to report estimates on a consolidated basis. So, as you can see on the slide, on a consolidated basis, our EBITDAX – adjusted EBITDAX for the quarter was $231 million.
We still think that it is important to evaluate the company on an attributable basis, but we also want to make sure that reported estimates are consistent. So starting this quarter, we will provide EBITDAX guidance on both a consolidated and an attributable basis, as we still feel it is important to understand each business separately.
Slide 7 is another example of CNX trying to provide the necessary information for investors to understand the different pieces of our business clearly. The attributable results subtract CNX's non-controlling interest in CNXM. This represents the percentage of LP units not owned by CNX, which is approximately 64%. For capital and cash flow from operations, our methodology is slightly different. For CapEx, we are backing out the capital that the MLP paid, which was $25 million.
If you look at CNXM's financials, you will see a gross capital number of $25 million and a net number of – $26 million and a net number of $25 million. The difference between the two, $1 million, is what CNX Gathering spent, which is shown on the slide.
For cash flow from operations, we simply took the same percentage mix at the MLP between gross adjusted EBITDA and adjusted EBITDA, net to the MLP, and applied it to the MLP's gross cash flow from operations. For reference, you can find the details of our approach on the slide footnotes.
Slide 8 provides our standard hedging update, which now goes out to 2023. In the quarter, we layered on about 16 Bcf of NYMEX hedges and 90 Bcf of basis hedges. And to reiterate, for 2018, we are more than 80% hedged on both NYMEX and basis compared to the midpoint of our guidance range. As I mentioned before, these locked-in revenues are de-risking our rapid EBITDAX growth and supporting our leverage ratio target confidence and share repurchase strategy.
I would like to close out by hitting some of our updated financial guidance metrics, which can be seen on slide 9. First, I want to reiterate that we are reaffirming our production guidance of 490 Bcfe to 515 Bcfe for the year. Next, on the cost side, we are slightly increasing our operating cash cost guidance for the year to $1.06 to $1.14 per Mcfe from the previous guidance of $1.01 to $1.11 per Mcfe. LOE is behind the cost increase and specifically water costs within LOE.
It is important to note that even though we are slightly increasing our 2018 guidance, we have seen substantial reductions in our total cash cost over the past year. All in, our cash costs have come down almost 11% or $0.13 per Mcfe since the second quarter of 2017. But as Nick mentioned, we're not satisfied and we'll continue to focus on driving costs down further.
Also, it's important to note, our 2018 guidance for other non-operating expense has improved by approximately $20 million for 2018, as can be seen on the slide. And finally, gas prices and other improvements more than offset the slight LO (13:47) increase. And we, as Nick mentioned, are increasing our 2018 EBITDAX guidance.
With that, I'll hand it over to Tim.
Thanks, Don, and good morning, everyone. There's a few key topics that I'd like to discuss today. First, I'll walk through the results of the quarter and highlight some of the recent operational and strategic developments, and then we'll dig into the drivers of the capital guidance changes that Don mentioned and look at the production cadence for the rest of the year. And then lastly, I'll spend some time discussing the recent deep dry Utica results and some of the exciting things happening on that front.
So, let's move to slide 10. Total production for the quarter was 122.6 Bcfe, which was a 33% increase year-over-year or a 5% decline compared to last quarter. Now, as we mentioned on the first quarter call, we were expecting a modest decline in the schedule as the schedule only contemplated three planned turned-in-lines for the second quarter.
Utica volumes were up again by more than 200% over the same quarter in 2017, driven primarily by growth in the Monroe County, Ohio dry Utica. I'll discuss the production cadence for the last two quarters of the year shortly. And as Don just mentioned in his remarks, total cash production costs in the quarter were at $1.09 per Mcfe or down $0.13 year-over-year.
Now, let's take a minute and look at the Virginia Coalbed Methane asset, which we don't talk about much, but recently there's some pretty exciting things happening down there. In the second quarter, operating costs were down 10% year-over-year as a renewed focus on efficiencies has paid dividends. A series of initiatives, including more data-driven analytics and a more effective use of manpower, has increased the rates of return for the entire asset.
And as we said before, Virginia CBM is a significant contributor to EBITDAX generation and remains a valuable piece of our asset base. These latest efforts have only cemented our confidence in the opportunity and help pull value forward.
Now, turning to slide 11. In the second quarter, we announced the Appalachian Basin's first long-term deal for a 100% electric frac fleet with Evolution Well Services. This deal is significant on a number of levels, but first and foremost for what it means to our frac cycle time efficiencies and our capital efficiency. Specifically, in the near term, we expect an increase of 30% in frac efficiency due to higher horsepower and less downtime.
On top of the cycle time efficiencies, the natural gas-powered fleet will drive an 80% reduction in fuel cost compared to a conventional diesel fuel fleet. There's potential for even greater cycle time improvements down the road as we continue to partner with Evolution and really test the capabilities of this technology. And on top of the economic impact of the Evolution frac crew, there is a series of health, safety and environmental benefits.
Moving on to slide 12, let's talk about development and capital plans for the back half of the year. As I mentioned, we turned-in-line three wells in the quarter, which were all in the Marcellus formation in our Southwest PA Central region. We also TDed three wells in the Shirley-Penns Marcellus and three wells in the Monroe County, Ohio dry Utica. Near the end of the second quarter, we brought on line our fourth rig and moved it to CPA where it's currently drilling near our Aikens and Gaut wells. More on that in just a minute.
And as you can see on the table on this slide, we've turned-in-line 17 wells year-to-date compared to our full-year plan of 68 TILs. The majority of the remaining turned-in-lines are scheduled for the second half of the third quarter. But due to the timing of when those approximately 30 wells get turned-in-line in the third quarter, we expect a modest decline in production volumes in the third quarter. But we then expect a significant ramp in production volumes in the fourth quarter.
It's worth noting that our expected TIL count has been reduced by six wells in 2018, which was the result of a scheduling change as the specific pad has been pushed into early 2019. Since those TILs were expected late in the year, there's not a meaningful impact to production volumes, and we are reaffirming our 2018 guided range of 490 Bcfe to 515 Bcfe.
As Don mentioned, we're increasing our E&P capital guidance for 2018 from a range of $790 million to $915 million to what it's now $900 million to $950 million. The increase can be attributed to three main buckets: first, drilling and completion remediation work; second, higher capitalized water costs; and third, the prepayment related to the Evolution Well Services agreement that I just discussed. There's also a modest amount of increase due to inflation in steel tariffs.
Of the total capital guidance increase, more than half was made up of the remediation costs and the higher-than-expected capitalized water costs. On remediation cost specifically, we had four separate pads impacted in the first half of the year that includes extended fishing operations on two pads where we had issues retrieving downhole equipment, and two Southwest PA, Marcellus pads where some abnormal conditions created issues with production casing cement that required repairs and drove slower cycle times. These issues have either been resolved or accounted for in the increase to the capital guidance.
Capitalized water cost increased due to higher-than-expected initial flowback volumes. And as you know, we reuse much of this water during completions of subsequent wells, which comes at a higher cost compared to fresh water.
Now, moving on to the deep dry Utica, in March, we turned-in-line the Marchand 3M, a delineation well in our CPA North region located in Indiana County, PA. The Marchand 3M is about 15 miles northeast of our prolific Gaut and Aikens wells in the Mamont area of the CPA South region.
The well currently flows into existing CPA gathering infrastructure and additional delineation wells are planned in CPA North, and infrastructure expansion has been deferred until more wells are drilled and midstream sizing can be properly addressed from an economic and NAV view.
On the bottom of slide 12 are some details on current and upcoming activity in CPA South. As I mentioned a moment ago, we brought in a new built-for-purpose deep Utica rig at the end of the second quarter. That rig is currently drilling the first of three wells on the Shaw pad and has already made it through the challenging Salina section without incident and at about half the cost of the original Gaut well. We would expect to see incremental improvement on each of the next two wells and all three Shaw wells are currently expected to be turned-in-line in the first half of 2019.
As the cost of these deep dry Utica wells trends lower, the economics become more and more attractive and more and more repeatable. And all that said, we have another rig operating in Mamont on the Bell Point pad. Early operations are running smooth and we expect to turn that well in line in the fourth quarter of this year. So, this is an exciting time for our CPA Utica operations, and we look forward to updating you as these wells come online.
Now on slide 13 is an update on the Richhill 11 deep Utica well in Southwest PA that we first previewed at our Analyst Day back in March. As you'll recall, the Richhill deep Utica wells are key to the stacked pay strategy as dry volumes from the Utica formation can be blended with damp Marcellus volumes. Those blended volumes can be sold as dry gas and avoid processing fees, which significantly increases the overall rate of return on the Richhill Field.
You'll see on the chart at the top of the page that the Richhill 11 well is currently flowing at an EUR of about 3.5 Bcfe per 1,000 feet or soundly above the guided type curve of 3.2 Bcfe per 1,000 feet. The well is also nicely outperforming the average peer well in Southwest PA or West Virginia from the last few years. We're currently forecasting a 12-month flat period for the well based on our current managed pressure drawdown strategy and the rate of drawdown to date.
On the lower part of the slide is a chart that shows the RHL 11 well cumulative volumes at or above the average peer well with a pressure drawdown that is substantially less than those peers. In other words, we're recovering roughly equal volumes at a much slower pressure drawdown and with a much longer runway. This performance gives us confidence in building a stacked pay factory and the prospects for Richhill blending strategy going forward.
That said, we're not known for resting on our laurels here at CNX. And on slide 14, there's a pair of images that demonstrates how we're using our earth model to optimize lateral placement in Richhill and elsewhere. The image on the left shows a proposed layout of two pads prior to the use of 3D seismic data. If those wells have been drilled as shown, there's a high likelihood of drilling and completions issues due to faulting. The image on the right shows how those two pads have been relocated and redesigned based on seismic interpretation to take advantage of natural fracturing.
We would expect that these especially tailored pads would avoid the drilling and completion issues related to natural fractures and realize higher rates of return. This data-driven analysis is particularly important in the Richhill Field, where the formation is more fractured and requires a precision engineered design.
So, there's a lot to be excited about around here, and we look forward to providing updates as the plans continue to become a reality. And with that, I will turn it back to Tyler.
Thanks, Tim. Andrew, can you please open the call up to Q&A at this time?
Yes, sir. We will now begin the question-and-answer session. The first question comes from Welles Fitzpatrick of SunTrust. Please go ahead.
Hey. Good morning.
Good morning, Welles.
Good morning.
So, it seems like Richhill, those results, they back up the stacked development mode. I think as of last update, it was going to be moving in development mode sometime around year-end 2019. Can that be accelerated at all on these positive results?
Well, there's always the opportunity to accelerate, but we've got a plan that we've laid out with the blending strategy, the sequencing of wells is important to be able to have the proper blending. So that's really built into our plan. And unless there's a significant change in the Marcellus development or the number of wells we're going to drill, there really would be no need to advance the Utica drilling.
Okay. That makes sense. And then the water trucking that you guys mentioned hitting in the second quarter, obviously, you took up (25:44) CapEx for full year, but it seems like the majority of that hit was in 2Q. Is that something that's going to mitigate going forward because of the locations of wells or maybe you've got more pipe in or something like that? Can you just talk to how that develops through year-end?
The water costs are really driven by the flowback volumes. The flowback volumes, we try to reuse as much water as possible. What we can't reuse, we have to dispose of and both of those options require trucking. So, whether we're disposing or reusing, it comes at a much higher cost than piping fresh water. So when we look at our frac water makeup, even though it costs a little higher, we live by our core values, and one of those is being a responsible corporate citizen and being environmentally compliant. So we try to reuse as much as possible. But that does come at a higher cost, so that drove our capital water costs up.
Okay. Great. And then just one last one, if I could. The fuel costs on the rigs dropping about 30% to 80%. Can you contextualize that for me? I mean, is that $50,000 a well? Is that $100,000?
I don't have the number right here, but it is significant. It goes from using a couple hundred Mcf per stage to getting – using a couple hundred Mcf per stage with this new frac fleet versus a couple thousand gallons of diesel per stage. And I don't have the exact number right in front of me, but I can get that for you after the call.
Okay. Great. That's all I have. Congrats on the continued success there in Richhill.
Thank you.
The next question comes from Holly Stewart of Scotia Howard Weil. Please go ahead.
Good morning, gentlemen.
Good morning.
Maybe, Nick, just kind of starting out, talking about all the different capital allocation options, you've obviously been pretty active on the divestiture side. Are there any assets out there right now that maybe you could fill holes or you think would be strategic to kind of the current portfolio?
Holly, I think that as time sort of marches on, the opportunity or the asset packages that are out there are actually growing. Some of those would fit quite well with us. But I will also say, and I want to really emphasize this and it's consistent with our messaging the past year or so, those acquisition opportunities, they have to compete with the rate-of-return metrics that we see from our organic drill bit capital as well as our share buyback opportunities. And right now – based when you run all that math, right now, share buybacks and our rate of returns tied to our CapEx program are clearly far and above something that would be a bolt-on acquisition opportunity.
So, I think the environment or the target-rich environment continues to grow. But right now, it can't compete, from our perspective, with the capital program that we've laid out along with our share buyback opportunities.
Okay. That's great. And that actually leads me into the next question. I mean, as where the stock sits today, is there any reason to think that you wouldn't finish this current authorization? And if so, are there plans to – or would there be plans to always just kind of have an authorization in place just in case you wanted to continue to take advantage of those opportunities?
There's sort of a short- and a long-term answer to that. In the short term, you saw that we extended out for a of couple months the current authorization. So, obviously, that implies an intention to continue to execute off of that. And in the longer term, back in March was the multiyear look that we laid out, the one side that showed how balance sheet capacity, cash flow capacity under that 2.5 times leverage ratio metric, coupled with all of our plans on capital, what that would do with respect to share count reduction over a number of years, which is sort of the bigger picture view.
That's, I think, the current view that we're willing to put forth today. As to what we do, say, in January of 2019, that's more of a wait-and-see and we'll probably have much more to say about that on the third quarter call coming up after this quarter concludes.
That's perfect. And maybe one final one for me. I know NGLs aren't a big piece of the puzzle right now, but just curious – and maybe this is for Tim, I'm not sure. With ethane pricing kind of doing what it's doing, is there anything that CNX can do just in terms of maybe extracting more ethane or being able to kind of increase volume just due to price?
Well, our ethane has – with some of the issues Mariner East had, we've had to reject some of our ethane this past quarter. But when you look at liquids prices in general, I think we have the opportunity to – with a flexible midstream system, we have the opportunity to move volumes to either a wet or dry system based on pricing, and we do that on a fairly regular basis as the market dictates. So when liquid prices are up, we can move more liquids to processing and take advantage of that and when they're not, we can push the blending more and more gas towards the dry outlets.
Okay. That's helpful. Thanks.
The next question comes from Joe Allman of Baird. Please go ahead.
Thank you. Good morning and thanks for the good update. My first question is on constraints. Are there any constraints that you're experiencing in the field? I know you just mentioned Mariner East, which was a constraint. But one of your peers talked about the kind of tight local crude trucking takeaway market. So, if you'd just talk about any constraints you're experiencing, that'd be helpful.
No, we don't have any constraints currently. When you look at our midstream system and our FT (31:54) and our takeaway points, we've got a fairly diversified portfolio from a transportation standpoint that allows us to move gas to several outlets. But on the trucking, trucking has been an industry-wide issue. We have not really seen an impact from it here. We're certainly aware of it. There is a shortage of drivers with – CDL drivers. But we started to recognize this last year and took some steps, particularly from a water hauling standpoint, to make sure we had the trucks that we needed locked up for a period of time.
That's very helpful. And then on a different topic, could you just talk about the implications of the Richhill well performance? And also, talk about the Marchand well in the same context. I didn't see any update on that well also.
Sure. The Richhill well, we're excited about it. It's producing above type curve. So, it really solidifies our belief in the blending strategy that we've put together for Southwest PA and those dry Utica volumes are going to be critical to developing the damp Marcellus gas, which is really going to give us an economic uplift and allow us to drill more of those wells sooner, and I'm referring to the damp Marcellus wells.
On the Marchand, there's been some public data put out there, but I would take into consideration that some of that public data that's out there was during our testing. So the rates vary a little bit. That well is producing into an existing system, and when we turn that well in line, prior to turning it in line, we were able to find some additional capacity on existing infrastructure. And when we considered that additional capacity along with the timing of future delineation wells, the right decision at the time, from a capital allocation and NAV standpoint, was to defer the midstream expansion until we drill some future wells.
And I know that raised – I'm sure raises some questions on well quality; are we going to drill more up there? And I will just tell you that we have more delineation wells planned in CPA North. And most likely, we will drill more wells off of the Marchand pad. So, that should tell you something about what we think of that area.
That's great. And then my last question is on your electric frac effort, I find it really interesting and it really shows kind of the innovative spirit you have there at CNX. Is there any reason you could not use that for every frac job going forward if you really find that successful?
There's no reason we couldn't grow into that. Yeah. We're already looking – as I mentioned, we're looking at ways that we can further take advantage of this technology and looking at what else we can do with it. It provides a lot of benefits not just from an efficiency standpoint, but from a safety and environmental compliance standpoint. It's a much smaller footprint. It's got a lot of pluses all around. So, we are looking at ways that we can further take advantage of it.
Great. Well, thanks very much. Very helpful.
The next question comes from Sameer Panjwani of Tudor, Pickering, Holt. Please go ahead.
Hey, guys. Good morning.
Good morning.
On the new frac spread contract and the added rig, were you guys able to benefit from the softness in the Appalachian service market as some of your peers have talked about?
I think whether we benefited from the softness of the market, I think we're able to find something here that we could take advantage of. We're excited about this because of what it brings to the table from a technology standpoint, but we're entering into it, I think really it's a win-win situation for both CNX and Evolution, and it helps us accomplish a lot of things we want to do. When we look at continuous improvement, when we look at a number of feet we can complete per day, this helps us move further down that road.
Okay. Great. And then on the Utica well, sounds like everything is continuing to perform pretty well. And just given your focus on technology and data analytics, are you able to get a good sense of the drainage area from these early results to better inform your spacing design as you head toward stacked development?
Yes, we do. That's one of the important things that comes out of the modeling and the data analytics. And as we've said before, the Utica is not as homogeneous as the Marcellus is. It's more compartmentalized. And we've got three or four significant compartments that we're focused on and we're continuing to learn more about each one. And they're not all at the same spot in their life cycle. So the spacing, completion designs, there will be variations from sub-area to sub-area, and that will be driven by the data set and the data analytics and what we're learning.
Okay. So you guys still feel good with your spacing assumptions from the Analyst Day regarding the Utica?
Yeah. We continue to update as we get more data in. We're always looking at our lateral spacing, our stage spacing, our landing points. We're looking at every aspect of those wells, really trying to move up that efficiency curve as quickly as we can, much faster than we were able to move up the curve on the Marcellus. So, we are still excited about the Utica, what it has to offer, and it is going to be a significant part of our growth plans going forward.
Great. Thank you.
And the last question today will come from Jane Trotsenko of Stifel. Please go ahead.
Good morning. My first question is regarding natural gas price realizations. They were especially strong this quarter. Was there something unusual this quarter that you could point out to? And how sustainable are these strong natural gas price realizations in the future?
So, yeah, I think there's lots of different things that are going into it, and I do think when you look at calendar year 2018 and just the supply/demand, storage fundamentals that exist, there's a lot of healthy fundamentals for gas prices. Q2 historically and Q3 have been a little bit different just based on in-basin basis differentials and components of that nature. We're much tighter now. If you look out in the next 12 to 18 months, all the pieces are in place from inventory levels to supply/demand balances to really allow, I think, healthy gas prices to continue throughout the rest of the year.
Thanks. My second question, could you please talk about free cash flow generation and production growth tradeoff, and how flexible is your five-year plan to changes in commodity cycles, both positive changes and negative changes?
Well, as you know, Jane, capital allocation is front and center to what we spend our time on as a management team. That's driven by rate-of-return metrics. So we're solving in the end for NAV per share. Production growth and CapEx budgets are more of a result instead of a target. When you look at where the gas price deck is at, which is what we run when we calculate all our rate of returns, adjusting for hedge book, of course, when you look at the forwards for both basis and NYMEX, basically, the strategy that we laid out in March with respect to the five-year plans and what that looks like from EBITDA growth to capacity on our balance sheet at the 2.5 times leverage ratio and potential opportunities, like share count reduction, I think that story is very much intact today as we sit here in the middle of 2018.
So, basically, when we look at the regulator, it's not so much free cash flow positive or negative. It's keeping a very secured balance sheet in the form of a 2.5 times leverage ratio and a robust hedge book. And then from that, where our capital allocation goes, whether it's debt reduction, share count reduction or capital program, that's driven by rate of returns and NAV per share. And looking out into the future, today versus March, we're still excited about the strategy we laid out for the five-year look that we provided.
Awesome. My final question is on NGL pricing as it was also very strong in 2Q. I believe it was partially due to higher ethane rejection this quarter, which raised the value of your NGL barrel. How do you see NGL price evolve for near term?
Well, we see the prices staying flat. But with some of the regional takeaways that's coming, high demand, we think there's some upside potential for NGL pricing.
I see. Thank you so much.
Welcome.
This concludes our question-and-answer session. I would like to turn the conference back over to Tyler Lewis for any closing remarks.
Thank you. All right. Thank you, everyone, for joining us. We look forward to speaking with you again next quarter. Thank you.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.