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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' Q3 2018 Earnings Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded.
I would now like to turn the conference over to Tyler Lewis, VP of Investor Relations. Please go ahead.
Thanks, Chad, and good morning to everybody. Welcome to CNX's third quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; Don Rush, our Executive Vice President and Chief Financial Officer; Tim Dugan, our Chief Operating Officer; and Chad Griffith, our Vice President of Marketing and President of CNX Midstream.
Today, we'll 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, CNX Gathering LLC, and CNX Midstream Partners LP. Earlier this morning, CNX Midstream Partners, ticker CNXM, issued a separate press release. And as a reminder, they will have an earnings call at 11 a.m. Eastern today, which will require us to end our call no later than 10:50 a.m. The dial-in number for the CNXM call is 1-888-349-0097.
As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risks, which we've laid out for you in our press release today as well as in our previous Securities and Exchange Commission filings.
We will begin our call today with prepared remarks by Nick, followed by Don and then Tim, and then we will open the call up for Q&A.
With that, let me turn the call over to you, Nick.
Thanks, Tyler, and good morning, everybody. Before we get into discussing our performance for the quarter and what we see in the future with CNX Resources, we'd like to begin today with a few moments talking about the events here in Pittsburgh that occurred over the weekend.
This community, whether it's the City of Pittsburgh or Western PA, it's been our home as a company literally for generations. And it's always been a tight-knit family-oriented and a take-care-of-our-own kind of a town and of a region. And that's why it's so hard to see something like this happen here. What happened the past Saturday morning, it's completely counter to all the values that this region was built upon. And we just wanted to extend our condolences as a company to all of our buddies and families out there who were impacted by this truly tragic event. So, thanks for letting us spend just a few seconds on that.
Now, let's shift to how Q3 unfolded and what we see with respect to opportunities into the future looking down the road. If I had to sum everything up, I would say basically that the team is firing on all cylinders. You see a lot of the evidence for that. We tried to summarize that in slide 3 with the slide deck that we posted. Consistent execution is driving production, capital efficiencies, economies of scale, they're driving costs lower. You couple all that with a locked-in hedge book for the year, and we are able to increase our full-year 2018 consolidated EBITDAX guidance to a range of $990 million to $1.01 billion and as compared to the prior guidance of what was $945 million to $970 million.
So I'll expand more on our share repurchase program on the next slides. But if you look at our last shares outstanding as of October 16, 2018, that's the date that's going to tie to the cover of our 10-Q when we file it, you can see that based on the midpoint of the guidance I just mentioned we expect to generate $4.91 per share of consolidated EBITDAX in 2018. And the math and the formula is pretty simple here. EBITDAX is growing while our share count is shrinking on a per share basis, which, in our opinion, is the only basis that matters for owners. CNX just keeps getting more and more compelling.
If you look at production in the quarter, we saw a modest decline, and we guided to that during our last quarter's earnings call. So, as expected, we ended up turning in line 35 wells. Most of those wells came on in the second half of the quarter. So, due to timing, production modestly declined compared to the second quarter, but it also sets up the fourth quarter for production to peak for the year.
If you look at our published turned-in-line guidance, we expect roughly 16 additional wells to get turned in line during the fourth quarter. That will bring the total to 68 wells for the year. And we've narrowed the full-year production guidance range to 497.5 to 507.5 Bcfe, which maintains the midpoint of the previous guidance of 502.5 Bcfe, so basically on track when it comes to production.
Our strong balance sheet, it continues to present us some NAV per share accretive opportunities. We continue to play offense in the third quarter. We bought back the remaining $200 million of our 8% 2023 notes. This saved us an additional $7 million in interest expense, and that brings our total annual interest savings looking into the future to approximately $18 million a year. These are real dollars driving real increases to our NAV per share. Our balance sheet has never been stronger, with net debt to trailing 12 months EBITDAX at 2.26 times. That's on an attributable basis.
Some people out there keep referring to the 2.5 times leverage ratio as our target. I think that's a bit misleading. If we were at above 2.5 times, having it as a target, I think that would be true, since we'd be managing to get down to the 2.5 times. But I think it's currently a bit inaccurate because we're already below that level today. And Q4, based on our guidance, it's only going to improve upon leverage ratio looking down the road.
More accurately, our healthy leverage ratio today, it creates optionality and adaptability. The balance sheet capacity will vary as capital allocation opportunities develop. And in this topsy-turvy energy world right now, there is a lot of capital allocation opportunity to take advantage of.
I think the biggest capital allocation opportunity was our discounted share price. Slide 4 sums up and provides some pretty compelling results. On the share repurchase front, we bought back an additional 8.3 million shares during the third quarter and, in total, through October 16 of this year, we bought back 27.6 million shares since the program started last year. That's a 12% reduction in our shares outstanding.
That's meaningful for several reasons, but the main reason, as I've said on numerous calls in the past, is that CNX was the only Appalachian E&P company to not issue equity during the prior downturn. We didn't lose discipline and dilute our owners at a bad time, and then have to start a share count effort already behind the eight ball, like many others are today.
Second, our job is to be great capital allocators, to grow the NAV per share of the company. We've conviction that our shares are undervalued in this misinformed market today, and for a capital allocator, that's not a frustration, that's not a complaint, that's an opportunity. And this capital allocator names CNX as all over that opportunity.
The fact that we were able to retire 12% of our outstanding shares at prices far below our NAV per share makes us very happy. And a duo of facts that we've got a strong balance sheet and a $300 million new authorization to keep going, that makes us even happier. So, thank you, Mr. Market.
Last time we checked, this is a commodity business and, as such, the low-cost producer wins the day. Our total production cash costs of $1.04 per Mcfe and our cash margins of $1.88 per Mcfe in the third quarter, those were driven by a powerful trio; we had low-cost dry Utica volumes, strong core Marcellus well performance, and last but not least, old-fashioned cost control.
Stacked pays, they situate us to drive costs down more and margins even higher. The deep dry Utica program continues to go well. We spud two additional wells in Southwest PA, and we're focused on driving down costs and optimizing well performance there.
You saw that we closed on the Ohio Utica JV sale during the quarter. We used the cash proceeds to pay down debt and repurchase shares. We have a distinguished track record of divestitures and there's no shortage of future opportunities for monetizations. We'll continue to be opportunistic in our approach and make decisions under the filter of NAV per share. So the same old story there when it comes to monetization opportunities.
I'd like to wrap my comments with a few remarks about the culture that's taking shape here at CNX is we approach the one-year anniversary of the new company. I think it's crucial to build and nurture a culture that both challenges and rewards the team and drives results for the company. The spin that occurred last November gave us the opportunity to reboot our thinking, and that's exactly what we've done. I think it's evident in the results from the quarter and for the year so far.
Our data-driven culture built around innovation and a challenge-driven mindset is coming into its own. We continue to focus on operational execution and excellence. We're mindful of the imperative that can constantly work to control costs across the board. And we work to simplify and streamline the way we do things to bring forward the most value for the business.
Most importantly, we must always be shrewd capital allocators. That's the foundation of our culture and our mindset as we go about our business every day. We don't sit idle. We constantly look for ways to push the envelope. We're executing in the field. Balance sheet is where we need it to be. And the mindset and culture we want, they're pervasive. I've been telling you for a while now how excited I've been about the future of the company. And I think these results and where we're heading demonstrate why I was so excited.
With that, now I'm going to turn it over to Don Rush to discuss some of the financials in a little more detail.
Thanks, Nick, and good morning, everyone. This quarter really highlights our ability to execute our strategy on all fronts. In the quarter, we generated significant free cash flow. We reduced our net debt. We reduced our leverage ratio to below 2.5 times. We bought back approximately 4% of the company. We lowered our cash operating costs. We brought 35 new wells on line. We added to our hedge book and we grew our consolidated EBITDAX per outstanding share by almost 150% year-over-year.
Slide 5 shows some of our financial stats. And I think it is important to reemphasize our strong cash margins of $1.88 per Mcfe for the quarter. It is clear our margins are benefiting from significantly lower cost, which Tim will touch on shortly.
Slide 6 highlights the attributable versus consolidated math. As I mentioned on the last earnings call, we will continue to show it both ways to provide clarity to our investors. And ultimately, it is important to understand both businesses individually as well as combined to truly understand our intrinsic value.
Moving to slide 7. We are approximately 80% hedged for 2018. In the third quarter, we added 123.8 Bcf of NYMEX hedges, and 99.7 Bcf of basis hedges out through 2023. As we have said, our hedging approach is a major component of our strategy. It's an important part of our balance sheet and gives us the opportunity to focus our efforts on risk-adjusted returns and NAV per share.
While discussing marketing, I would like to highlight that our 2018 volumes are expected to be comprised of 7% to 8% liquids, which you can see on slide 8. And in the quarter, strong NGL pricing definitely helped increase overall realizations. However, it is important to note that NGLs are difficult to hedge and, as we have witnessed, very volatile. This is the reason we have taken a flexible approach when it comes to NGLs. Our wet and dry midstream systems and our asset base allows us the flexibility to adjust as liquids prices change, instead of trying to guess what they are going to do next and predict the future.
On slide 8, you can see we have updated some of our 2018 financial guidance. Most notably, as Nick briefly mentioned, we increased our 2018 EBITDAX guidance by approximately $50 million compared to the previous guidance. Our cost and E&P capital guidance remains unchanged, and we narrowed our 2018 production range while keeping the midpoint the same.
Our consolidated capital for 2018 increased slightly due to our MLP CNX Midstream increasing its 2018 capital guidance this quarter. We will touch on this in more detail during the Midstream call, but essentially, CNXM made a strategic land acquisition, upsized their systems due to CNX well improvements, and accelerated some additional projects and construction activity from 2019 into 2018.
With that, I'll hand it over to Tim.
Thanks, Don, and good morning, everyone. We had a very busy and a very successful third quarter. As we've said before, CNX has transitioned firmly into execution mode and we're excited to show how our success in the field is driving NAV per share growth of the company through capital allocation, well quality and operating costs.
Now, starting on slide 9. Production in the quarter was 119 Bcfe, an 18% increase year-over-year and about a 3% decline quarter-over-quarter, as we expected and as we communicated on the second quarter call. The quarter-over-quarter decline was the result of our activity cadence and turned-in-line timing. And I'll discuss how we expect the end of the year to pan out in just a minute.
On the bottom left of slide 9 is a chart that we're pretty proud of at CNX. As you can see, total production cash costs have fallen to $1.04 per Mcfe or 17% lower than the same quarter last year. The quarter-over-quarter reduction of roughly 4% was driven largely by lower LOE, which benefited from decreased water disposal as we reused more produced water for our fracs. And by the way, our total Utica Shale production cash costs in the third quarter were just $0.56 per Mcfe, driven by the significant per-well dry gas volumes.
The chart on the bottom right of this slide illustrates another major driver of our lower cash costs. Our industry-leading low firm transportation and processing commitments, which we feel is a major competitive advantage relative to peers. This fixed high-cost transportation does give our peers access to other markets, but the cost of that transport is usually greater than the price uplift they see. We expect this advantage to become clearer as additional pipeline projects come online and become an increasing burden to our competitors.
Turning to slide 10. This highlights our third quarter development in what we expect for the remainder of the year. The company turned in line a total of 35 wells in the quarter, and we're on track to reach our previously stated guidance of 68 turned-in-lines for the year.
For those of you doing the math, our implied production growth in the fourth quarter compared to the third quarter is about 10% based on the midpoint of full-year production guidance. While this is a significant ramp, we continue to see strong early results from the recent turned-in-lines, which are steadily outperforming legacy wells. And we'll have more on that in just a minute.
We are currently running four horizontal rigs, three in our core Southwest PA Central Marcellus area and one in CPA South on the Shaw deep dry Utica pad we discussed last quarter. We have two top hole rigs running on two multi-well Utica pads in our Morris and Majorsville areas of our Southwest PA Central region.
The Morris 10 activity is a return trip to an existing Marcellus pad with flowing production, which will benefit from stacked pay efficiencies and potentially simultaneous operations. The Majorsville 6 pad is new construction and is situated near our Richhill Marcellus and Utica field. Both pads are expected to spud in November and wells should be turned in line in the second half of 2019.
We're applying lessons learned and techniques developed on earlier CPA in Southwest PA deep dry Utica wells, like the Richhill 11E, and quickly moving into factory mode. To-date, the Richhill 11E continues to flow above its type curve and has yet to hit line pressure.
Moving on to slide 11. As I mentioned briefly, the wells we've turned in line over the past several months continue to outperform previous wells in the same fields. For example, on the top of the slide, you can see how the Morris wells from 2018 compare to both the legacy Morris wells turned in line in 2012 and 2013, as well as the expected type curve from our Analyst Day materials.
What you'll notice is that the 2018 wells have EURs that are 77% higher than the legacy wells and that the new wells are consistently hitting the expected type curve. This strong performance is the result of carefully designed inter-lateral spacing, stage spacing, increased proppant loadings, and optimized drawdown procedures, among other technical improvements. These results are proven and repeatable.
In the Richhill field, the latest turned-in-lines are much younger, but the overarching story is the same. Early cumulative production far exceeds the legacy Richhill wells from 2015 and 2016 and are flowing at or above expected type curves, as laid out in the Analyst Day materials. These wells are benefiting from shorter stage lengths, higher proppant loadings, and wider spacings, on top of other technical advances deployed in the Morris field.
So, why is this important? Well, the Morris and Richhill wells are expected to make up approximately 80% of our Marcellus turned-in-lines in 2019. This is why we're so confident in our rate of return expectations for the next year and why the drill bit continues to be a top capital allocation priority. And by the way, these pads are all designed for stacked pay development to allow for blending in Richhill and take advantage of other capital efficiencies, like simultaneous operations that I mentioned earlier.
Now, let's turn to slide 12 and talk about some of the exciting things happening in the Central PA deep dry Utica. As we previewed on the second quarter call, our fourth rig came online in late June in CPA, where it began drilling three laterals on the Shaw pad. Due to the drilling efficiency of those three laterals, consistent core and log results and the prospects for takeaway capacity, we added a fourth lateral to the Shaw pad. Those wells are expected to be completed in the next few months and turned in line in the first half of 2019. In the past few weeks, we turned in line the Bell Point 6 delineation well located just northeast of the Gaut, Aikens, and Shaw pads. We're excited by the early indications we're seeing from this well.
The charts on slide 12 show just how far we've come regarding drilling efficiency in the deep dry Utica. On the upper left, you can see how much costs have fallen relative to the initial Gaut well drilled in 2015. At the bottom of the slide, the chart demonstrates how quickly drilling has improved on a days-versus-depth comparison. All of these data points make us more and more confident in our ability to reach full development mode in this region and do it with a high rate of return.
Looking now at slide 13, we often get asked about just how far we can push the efficiencies we've gained over the last few years and what the rate of change looks like now compared to the early days. The fact is, we don't rest on our laurels, and Nick highlighted some of the exciting changes in our culture. As such, we're always looking for new ways to optimize every facet of our development process.
Since our Analyst Day back in March, we've reached several new milestones, including the drilling of a 7,200-foot Marcellus lateral in just under 11 days from spud to TD, a peak completion speed of 2,600 feet per day or 13 stages in 24 hours, and we're currently averaging seven days from the moving of a drilling rig offsite to the start of a frac job. These are the kind of metrics a company reaches when everyone's focused on capital efficiency throughout the organization and across our service partners.
On the planning front, we've continued to examine and re-examine our development plans and have been able to add more than 700 feet to average lateral length going forward. We've also utilized remote fracturing and subgrade wellhead designs to mitigate PDP shut-ins, particularly on return trips to existing pads.
Now, lastly, we continue to push the envelope from a technological standpoint across all of our operations. As we announced last quarter, the Evolution all-electric frac crew will be starting up in the first half of next year, which will drive meaningful cost efficiencies and HSE benefits.
We're also very excited about a new casing design program that helps to reduce frac treating pressure, which in turn reduces non-productive time and allows for higher rate of treatment in greater fracture complexity. We believe this design could result in potential net savings of $250,000 to $500,000 per well when implemented.
We are continually evaluating the latest technology and advances that we see across the industry that we can apply here in Appalachia. And like I said at the beginning, our focus remains on driving the NAV per share growth of this company. And we have an array of tools at our disposal and the best sandbox to make that happen.
And with that, I will turn it back to Tyler.
Thanks. Operator, if you can open the call up for Q&A at this time, please?
Certainly. The first question will be from Kevin MacCurdy with Heikkinen Energy Advisors. Please go ahead.
Hey. Good morning, guys. My first question is on the repeatability of lower LOE cost. Will that roll forward? And is there any room to increase the amount of water you are reusing?
Well, Kevin, I think when you look at our track record and the efforts we have put forth on managing costs and our drive for continuous improvement, and then you look at the cash cost trends that we've highlighted for both the deep dry Utica and the Marcellus, I'd say that over the long-term the results are very repeatable and there is room for additional improvement.
And on the waterfront, we continue to utilize as much of our produced water as we can in our completions, and we'll continue to do that moving forward.
Great. And on the higher NGL volumes this quarter, how much of that was driven by ethane recovery and how maybe has that trended throughout the year and will trend throughout the winter?
Yeah. Hey, this is Chad Griffith, Kevin. I'll take a shot at that answer. We did have increased ethane recovery during the quarter. It was a little bit of a – we sort of hit the floor and we had to increase recovery of ethane at one of the processing facilities. So, that's going to increase your NGLs recovered for the quarter and it had, because it was ethane, it sort of brought that weighted average NGL barrel down for the quarter.
That's probably a one-time thing. When we look at ethane recovery, we have a lot of optionality with ethane. We have available de-ethanization capacity and we really just look at what's the best economics for that ethane. Is it better to reject it and leave it in the gas stream or to recover it as ethane? And we've got a lot of optionality there, and we optimize that really on a month-to-month basis.
Got you. So the economics are not in favor of recovery at this point?
It's pretty neutral. It's really very neutral right now. So, recovering a barrel of ethane is almost exactly equivalent to the value or the heat (25:07) content of that ethane.
Great, guys. Thanks for answering my questions.
The next question will come from Holly Stewart with Scotia Howard Weil. Please go ahead.
Good morning, gentlemen. Maybe just the first one, given the majority of your 3Q wells were brought on in kind of the latter half of the quarter, could you provide us an exit rate for 3Q and just to give us a sense of kind of your ramp into 4Q?
Well, Holly, I think with the majority of the turned-in-lines coming in the third quarter and then the quality of the wells, we're going to see our peak production for the year in the fourth quarter. But at this point, I don't think we've laid out an exit rate.
Correct.
Okay. And then maybe, Nick, is the plan still for 2019 guidance in January?
Yeah. That's the plan we're looking at. Like I said in the commentary, all the capital allocation opportunities that we've got across the drill bit that Tim highlighted, share count reduction options and how that all balances out, we'll have more to say about that looking into the future come January when we cover Q4 results for the year.
Okay. Great. And then a couple of your projects on the pipeline side went into service in October. Curious if you're utilizing that Nexus capacity right now, I guess same question for Mountaineer Xpress, and then kind of how do we think about those two project impacting 4Q GP&T?
Thanks, Holly, for the question. For our Nexus capacity, our capacity has not yet actually started. They only turned their greenfield portion into service. And so, we're still waiting for this full path to come into service, which we're really expecting at any time. So, that portion is not in service for us yet and so we're not yet using Nexus. So, that demand charge has also not yet started for us.
On the Mountaineer Xpress piece, as you know, that's sort of a two-piece project. The portion that reaches back to Majorsville and Southwest PA is much more, I think, strategically important for Appalachia. It was only the West Virginia portion that came in service. And we have been able to find some gas to buy to fill that capacity. And we've been releasing some portion of that capacity that we've not been using. But by and large, the most important piece of that to us is the Majorsville piece and we're expecting that early Q1 of next year.
Okay. And then I guess any impact that we should kind of think through for that 4Q expense line with those projects?
I mean, I think that's already baked into the guidance we provided.
It's baked into the full-year guidance, Holly.
Okay. Great. Thanks, guys.
The next question will be from Welles Fitzpatrick with SunTrust.
Hey. Good morning.
Morning, Welles.
Can you talk about – so, obviously, there's no expiration on the buyback. Can you talk about your plans in that regard? I mean, are you going to try and – I know you have an NAV-based approach, but is that going to be paired with drops? Are you allowed to use the RBL to buy back shares if you see something especially accretive to the NAV? Can you talk about the methodology going forward?
Yeah, sure. And I think the easiest way to explain it is it'll be a similar approach that we've used here to-date. As we've stated, we are comfortable using our balance sheet capacity below our leverage ratio ceiling. And as you kind of hit on, we do use a NAV per share risk-adjusted return-based approach to make the decisions. And we weigh the opportunity to buy back shares against current and then future opportunities that the company has outside of share buybacks.
So I think, going forward, you'll see a lot of the same that we've been doing, which is I guess a blend of being opportunistic, coupled on the other hand with being prudent and patient when appropriate as well. So, comfortable either direction whether it's balance sheets or future changes in the business to go ahead and take advantage of things when we see an opportunity.
Okay. Perfect. And then, if we could talk about this new casing design a little bit, is that something that you see as applicable to across your acreage or are there certain portions that you'll be testing first as we go forward?
Right now we see it as being most applicable to our deep dry Utica development.
Okay. Okay. Perfect. And then so for the – I believe there's a blended stacked 9,500-foot lateral, would that apply in that quarter to $0.5 million savings? Does that take that under $8 million? Am I doing that right?
You're referring to the targeted well costs for the type curve assumptions wells, I'm assuming?
Yeah. That's correct.
Yeah. Talking about drilling and completion dollars, $8 million will be more of a Marcellus target. We're below that on the Marcellus. But right now, we put out our Utica target of $12 million and we are quickly approaching that and we would expect this new casing design to have an impact on that.
Yeah. Welles, just to follow...
Okay. Perfect. Thanks.
...the $12 million we talked about, it was a $12.5 million target assuming a 7,000-foot lateral for the Utica.
Okay. Okay. That's perfect. Thank you.
The next question will be from Sameer Panjwani with Tudor, Pickering and Holt. Please go ahead.
Good morning, guys. You talked a little bit about future monetization opportunities. But the focus on potential drop-downs, I think the EBITDA potential here is expected to grow to $200 million by 2020. So, can you just give us an update of where that stands today on a run rate basis kind of heading into 2019 and if any of the retained assets are entering a phase of maturity or fit within the development program where it wouldn't make sense to move them to the MLP in the near future?
Yeah. So, going back to some of the Analyst Day materials that were posted, whenever that was, in March, we walked through sort of the EBITDA ramp from where it sits currently to the $200 million, which was like a 2020-type timeframe number. So, the assets that area comprised in that are in various stages of maturity.
I can tell you that, between CNX and CNXM, we're always hard at work trying to find win-win opportunities that make sense. So, as to when and if these get done and which ones in the order of which ones would go in, still very much work in progress, but I can tell you we're constantly searching for opportunities to create win-win scenarios. And once we do find one, I think our track record has shown, we're quick to act on it once we do kind of figure out what we want to do.
Okay. Great. And then, given the focus on NAV per share, how do you think about moderating go-forward growth with the forward curve approaching $2.50? I think some of your peers have already messaged slower growth in 2019. And I just wanted to get your thoughts on allocating capital more aggressively towards buybacks.
I think you kind of mentioned this a little bit and kind of referenced it in some of the Q&A, but I think what would be helpful is just trying to get some context as to how you rank the opportunity set or the rate of return between buybacks and D&C activity, given where the forward strip sits today.
Yeah. So, a few different pieces to that question. First, I mean, we're eyes wide open on the forward strips. I think we do a good job of paying attention to them and making sure that we're making decisions with it in mind and not just drilling and hoping they get better.
Second, we're constantly reevaluating our capital allocation opportunities with the new variables and inputs that occur, whether it's NAV per share, or technological advances, or what the peers are doing. So it's a constant mix as we're re-ranking these opportunities going forward.
Third, our production process is simply an output. We don't back-solve for 5%, 10%, 20%. That's all just really an output. The focus really is on risk-adjusted returns and where to best put our capital to use. And I think going forward you'll see similar to going backwards, it's hard to do all of one and none of the other in a lot of these circumstances.
So it'll be a mix that kind of help each other out. I mean, the more returns we're able to create via the drill bit, the better returns look on other pieces of our portfolio as well. So they kind of go hand-in-hand and we're constantly screening them and making decisions as variables change.
Okay. Thank you.
The next question will be from Jane Trotsenko with Stifel. Please go ahead.
Good morning. The press release highlights that your production costs are lower in Utica than in Marcellus. Could you please comment on the competitiveness of your remaining Utica assets as it relates to the Marcellus assets in your portfolio, and if you see a higher rate of change in Utica versus Marcellus?
Well I think, I mean, the Utica and the Marcellus compete very well with each other, but they're very different. The Utica is dry gas. The Marcellus has a blend of wet and dry gas. But when you look at the rate of change, right now the rate of change is more significant in the Utica because we're earlier on in the development of that play.
But they both generate great returns. We put our development plan together in a way that maximizes our returns, and that's really what we focus on. But we're continuing to move forward with the Utica. We're a first mover there, we're a front-runner, and with that, we have a significant competitive advantage. So we take advantage of that as much as possible.
So, let me just kind of elaborate on that. So, Utica, you have three assets, right, a little bit what is left in Ohio and then West Virginia and Central PA. Could you just maybe talk in terms of returns? Is it like Central PA has the highest returns relative to your other assets?
No. I think they all provide significant rates of return and they're all different, and they all provide different benefits. In Southwest PA, as we've talked about in the past, the Utica is critical to our blending strategy with the damp Marcellus wells and the stacked pay provides increased rates of returns for both the Marcellus and Utica.
In Central PA, we have the same type of uplift, but the Utica in Central PA is really the driver there in that Utica, because of the existing assets that will already be in place for Utica wells, will uplift any Marcellus development that takes place on a stacked-pay basis.
Okay. Okay. Got it. The next question relates to the realized natural gas pricing. I saw that it improved by more than the improvement in Henry Hub pricing in 3Q. Could you please comment on your exposure to in-basin pricing and how much gas is sold on a spot basis versus (37:28) pricing?
Sure. So, we take a little bit different approach to FTE, differentiates us from a lot of our peers. We have the lowest FTE commitments of any of our peer group. And that just ultimately results in us selling a lot of gas locally and then taking advantage of these other projects that are coming online to lift that in-basin price.
And that's really what we saw the trend here in Q3, coming into Q4, these projects coming online, moving gas out of the basin, and improving our local price. And we were able to receive the benefit of that improved local price without really signing up for big pieces of this export capacity like some of our peers have had to. And I think so...
Okay. And the spot basis and (38:20) pricing, like, how much is sold on a spot basis if you sell any of your gas on a spot basis?
So we optimize our sales book sort of real-time basis, right? So we've got a mix of seasonal deals, we've got a mix of term deals, mix of 1st of month and a mix of spot. And really, we look at market conditions every month and sort of optimize that portfolio based upon what we see happening in the marketplace.
Okay. Okay. Thank you so much.
The next question will be from John Nelson with Goldman Sachs. Please go ahead.
Good morning. Thank you for taking my questions. And certainly, our hearts and condolences also go out to the Pittsburgh community.
Nick, I'm afraid I might be one of those folks you referenced in your prepared remarks who needs a better understanding of the leverage target. Was hoping to kind of focus a little bit on the text on slide 3. So, not trying to mince words, but I guess to better understand the leverage target, is it something that you folks would be comfortable going above for a period of time in particular to be opportunistic on the share repurchase program, or should we be thinking of it as a ceiling?
Yeah. So this is Don. I would think of it a couple of different ways. So we get asked this question a lot. Are you looking at trailing 12 months, last quarter you annualized, next 12 months? And, really, we look at this as just a going concern kind of business leverage ratio target. So we look at not only 2018, but 2019, but 2020, 2021. We look at the cash forward strips, we stress-test it.
So it's a blend that allows us comfort coupled with our hedge book, low-cost position and kind of where assets sit on a cost curve to allow us to really have this strategy unfold. So, taking any of the pieces in isolation doesn't quite make as much sense as they do all together. So the 2.5 times is really a ceiling, but how we think about that 2.5 times is much more dynamic and all encompassing as opposed to a snapshot-point-in-time measurement.
So it could be more 2.5 times ceiling on a forward expectation is maybe the way to interpret that?
We bought back shares in Q1 and Q2, and we weren't at the position that we're at today. So we had a clean line of sight, and we prudently and patiently did it over time with the visibility that we would be here where we're at today with confidence.
So it's a blend of viewing it as a ceiling. It's a blend of what our hedge position looks like going forward. And so it's, say, a blend of kind of all the factors that really stress-test the viability of a business. So the 2.5 times ceiling is a kind of a linear one way to look at it, but it's encompassed with a bunch of other pieces that kind of roll in to ensuring that you have a strong balance sheet, a strong business. And if that answer is yes, then we feel comfortable using our capacity for opportunistic NAV per share accretive uses.
Okay. And again, not trying to mince words, I really just wasn't sure how to interpret the adaptability kind of line item there. Is that kind of signaling that you think that should go down over time, or really just wasn't clear on kind of what the takeaway should be from that word?
John, this is Nick. The adaptability was mentioning and referencing our ability to move quickly because in part of our balance sheet as conditions change. This could be forward pricing, this could be EUR improvements, this could be share price changes with respect to CNX stock. And being at the 2.26 or so leverage ratio of Q3 and then with the guidance that we put out looking at what Q4 EBITDAX is doing, that leverage ratio, all things being equal, is only going to be lower.
So, adaptability specifically just speaks to the ability to move quickly as these extraneous and external and internal assumptions change. And then the leverage ratio being where it's at, coupled with our cash flow ramp in Q4, puts us in the position that Don's talking about.
Yeah. And, to add to that too, the hedge position really gives us time to adapt. So, if things change, it doesn't change for us next quarter. We have a hedge book that gives us a runway to modify as we see fit for circumstances in the future with gas prices. So it gives us time to adapt as circumstances change around us.
That's really helpful clarification. And then just last one for me. The $300 million kind of incremental program the board authorized, any color on just how that figure was targeted? And I know it has an open-ended time horizon on it, but is there an expectation that over what period of time you all expect to be able to complete that?
I think as we've been kind of talking to for a while now, it's just constantly going to be a tool in our tool box that we'll have to use. So, ultimately, kind of pointing to time horizons is unnecessary. We view it just as a part and parcel of the way we run the business and we run the company. So it's just part of our ongoing decision making that will always be there for us to use if we choose.
Great. I'll let somebody else hop on. Thanks again.
Ladies and gentlemen, this concludes our question-and-answer session. I would like to turn the conference back over to Tyler Lewis for any closing remarks.
Great. Thanks, Chad, and thank you, everyone, for joining us this morning. 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.