CNX Resources Corp (CNX) 2017 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the CONSOL Energy's First Quarter 2017 Earnings Results Conference Call. As a reminder, today's call is being recorded.

I would now like to turn the conference over to the Vice President of Investor Relations, Tyler Lewis.

Thanks, Nick, and good morning, everybody. Welcome to CONSOL Energy's First Quarter Conference Call. We have in the room today: Nick Deluliis, our President and CEO; Dave Khani, our Chief Financial Officer; and Tim Dugan, our Chief Operating Officer.

Today, we will be discussing our first quarter results and we have posted an updated slide presentation to our website. 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 begin our call today with prepared remarks by Nick followed by Dave, 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.

Well, thanks, Tyler, and good morning, everybody. Highlighted in the morning's press release, there were 3 important and critical achievements that developed this quarter. Now the first one was from an operations standpoint. And if you look at our operational performance, cycle times have been dramatically reduced, capital efficiencies up and the tight curves have been further optimized in some of our fields. All of these items have contributed to 2017 and 2018 production guidance increasing. So for 2017, we're increasing guidance to 420 to 440 Bcf and for 2018 we're increasing guidance to 490 to 520 Bcf. Those both compared to the prior guidance numbers of 415 Bcf for 2017 and 485 Bcf for 2018. And we did that without increasing the previously announced '17 and '18 capital plans. So it's a really significant achievement and of course a driver of our NAV per share.

The second development was that we monetized over $100 million in non-core E&P assets to date so far this year. We expect to be over halfway to the high end of our $400 million to $600 million asset sales target by the end of the second quarter. So we got off to a good start there.

And then the third development that was significant, we generated approximately $100 million of organic free cash flow in the first quarter that excludes asset sales. And we used the organic free cash flow to pay down debt at a discount and further reduce interest expense.

So these are 3 very important achievements, they're fundamental drivers as we continue to pursue our strategic goals in 2017 and beyond. And taking a step back beyond these critical achievements so far this year, we'd like to add how a unique situation for the Appalachian basin and perhaps for all the E&P as unfolding with CONSOL Energy. We have, over the past 5 quarters, we're currently in early 2017, and we will continue in a future to be a company who exercises a disciplined capital allocation philosophy across the premier asset-base. And we're doing it in a way where we deliver the best of both worlds, as production growth and free cash flow generation. We delivered both in a big way throughout 2016, we did so again in the first quarter of this year and we expect to continue to do so throughout the remainder of '17 and 18. That's a unique trait in Appalachia, and it's a characteristic that creates all kinds of opportunity across a range of options to grow the intrinsic value for our ownership.

Now I'm going to let Tim Dugan cover more the specifics, regarding the operational achievements and the exciting things that we continue to see there along with the improvements in type curve optimizations. So in the meantime, I want to spend the remainder of the time, I have with you, on the second and third developments that I mentioned for the quarter.

Over the years, our monetization program has seen tremendous success and that's been illustrated by CONSOL being the beneficiary of billions of dollars worth of proceeds. The majority of those asset sales historically been coal related and have netted the company over $5 billion since 2012. This quarter, however, highlighted a step change in what we began and when we began monetizing non-core E&P assets. Why is the step change important? Well, I'll remind you, as we discussed in the past, one of the most significant benefits of the Marcellus joint venture dissolution, which wrapped up in the fourth quarter of last year, was the fact that the separation gave CONSOL 100% control of our future development pace as well as strategic control of our assets to include divestitures. As such, the ability to divest acreage that falls outside our 10-year plan, it becomes a lot easier. We recently closed on 3 transactions, which in aggregate total approximately $108 million. And since 2 of those transactions closed after the end of the first quarter, we've only received about $16 million of those proceeds as of March 31. In addition to those initial proceeds, we expect to receive around $92 million in the second quarter.

Now on top of those initial asset sales, we've got a handful of more in process. Another potential asset package, which is currently in the held-for-sale category in our SEC guidelines highlighted in our 10-Q that's going to be filed, is the plan to sell 12 producing wells, 15 docks and roughly 15,500 net developed and undeveloped acres in Doddridge and Wetzel County in West Virginia. I don't want to go into the specifics beyond that, but it's important to highlight that with the sales that have closed to date (technical difficulty) along with those that are currently in process, we think we have the momentum to reach our target of $400 million to $600 million in 2017, for asset sales, in addition to reach in a halfway point to the high-end of the guidance by the end of the second quarter.

The third development I mentioned, that we generated around $100 million in organic free cash (technical difficulty) flow, again, that excludes asset sale proceeds, and we used that free cash flow to pay down debt at a discount.

It's important for a couple of reasons. First, yet again, we generated organic free cash flow from continuing operations. Second, we continue to execute on further reducing debt to reduce our leverage targets. And last but not least, with proceeds coming in from closed asset sales, we expect the second quarter will be even better than the first in terms of delevering.

With continued organic free cash flow generation and proceeds from asset sales, we're expecting that our total company leverage ratio will decline to the low 2s by year end. Since the strong leverage ratio allows us to execute the separation of our coal and E&P businesses, let me provide a brief general update on the separation front.

Now as we said before, we're running a dual process in parallel to maximize the outcome. The first process is an outright sale and the second process is a spin transaction. We've retained Credit Suisse and Bank of America Merrill Lynch to assist with these processes. We're pleased with the level of interest. The sales process is generated from strategic buyers as well as financial sponsors to date, but also we're pleased with the progress we're making with the preparations for a spinoff. We don't have a timetable for the completion of the sales process or the spin process but, as we said previously, we expect to complete the separation in 2017. Beyond that, I really don't want to get into many details other than it really is going to boil down to selecting the path that optimizes the best NAV per share opportunity for the shareholders.

To briefly summarize and foreshadow some of the key beams you'll hear from Dave Khani and Tim Dugan in a minute, production is up, capital's flat, asset sales are on track, our hedge program protects us from future volatility, and year-over-year our quarterly costs are lower even though production was down slightly because of the tight in-line scheduling. We've got a rigorous plan that will yield significant growth over the next 2 years and, at the same time, we don't expect any inflationary pressures for service cost due to contracted frack crews along with expected efficiency improvements that Tim's going to talk about. In short, everything is falling into place as we continue on the path of separating and continuing to transform the company.

This all leads to the topic of capital allocation, something that you've heard us speak about for a handful of quarters now. All the arrows that are pointing up for CONSOL will create opportunity for important capital allocation decisions in the coming months. From a development standpoint, we continue to evaluate and draw our highest rate of return areas first. These decisions continue to evolve, especially given our continued success in the dry Utica, Tim's going to talk about that in some greater detail. On a corporate level, we remain focused on using free cash flow to further reduce debt to get our leverage ratio down to the low 2s in 2017. In following the company reaching its target, along with the separation of our coal and E&P businesses, we're going to be in a position where we can then pivot to a number of potential options. If we feel we're still trading at a significant discount, or NAV per share, and we certainly believe that today, a share repurchase program is an option. We could plow funds into the drill bit or we could look at M&A acreage opportunities. Whichever way we go, we're going to look at this in an opportunistic fashion and not a prescriptive one. And our decision ultimately depends on where we see the highest rate of return and NAV per share impact. So stay tuned on that front, much more to come this year.

With that, now, let me turn it over to Dave Khani.

Thanks, Nick, and good morning, everyone. I have 5 key takeaways in the quarter. First, since that -- our last earnings call, production guidance is up, prices are up and cost are up slightly. We increased our 2018 to 2020 hedge position by another 25%. This all results in higher margins, returns and a second EBITDA guidance increase for the full year since the Analyst Day.

Second, we posted solid free cash flow numbers and our leverage ratio declined by half the current of 3.9x and we're on pace to exit year around 2x. Once we dropped below the 2.5x level, we will have increasing flexibility to use free cash flow to drive our NAV per share growth even faster.

Third, we executed a significant portion of the asset sales, as Nick highlighted. This, along with our improved E&P operating cash flow, increased our free cash flow outlook for 2017 and 2018.

Fourth, CNXC reported first quarter results and raised guidance by 5%. Coverage ratio has hit 1.2x for first quarter '17, the improved forecast will help our separation process.

And fifth, we hope this call answers 2 main questions we consistently receive on the E&P front: Can we grow production meaningfully? And do we have the outlet to sell it at a reasonable margin despite not having an extremely large FT book?

Shifting to the results for the quarter and highlighting slide 18, CONSOL reported adjusted income and EBITDA from continuing operations of $38 million or $0.17 per diluted share and $217 million, respectively. On a GAAP basis, the company reported net loss from continuing operations of $39 million attributable to CONSOL shareholders, primarily reflecting the $138 million impairment related to the sale of Knox and coal field assets, the $25 million unrealized gain on commodity derivatives and $5 million in various nonrecurring fees. As we monetize assets and streamline our company, we will continue to experience gains and losses. We would expect to realize gains on the next set of asset sales.

Let's move over to guidance. We're increasing our EBITDA guidance for 2017 by 7% over the February earnings release, driven by higher production and improved basis outlook, partially offset by moderately-higher operating costs and some higher post-retirement costs. In the first quarter, we beat most of our internal forecasted items including production, as a result, we've raised guidance. On the production front, the only point I will make is that, our production increase is tied to improved recycling ratios and capital yields that Nick highlighted, as well as an improvement in our pipe conversion costs.

Now let's talk about operating costs, which increased in the quarter. Our per unit LOE continues to tick down by about $0.04, but our gathering, processing and transportation costs increased about $0.10 as a result of higher percentage of gas getting processed, resulting from the JV dissolution and 2 onetime catch-up items from our Ohio wet, Utica and our CONE fees.

Moving forward, we expect to see a sharp reduction to operating cost over the next 2 years as we expect to bring on more dry gas production. Our dry Utica operating costs are materially lower than our Marcellus, and it is the single biggest driver in reducing our cash operating costs. Couple this with significant expected decreases to Utica D&C costs, which Tim will touch on, drive higher rates of return than our Marcellus. This is why we are much more bullish than our peers on the dry Utica. We expect dry Utica volumes to jump about sevenfold by the fourth quarter of 2017.

Now let's talk about coal. CNXC reported its first quarter earnings last night and posted strong results despite another mild winter. CONSOL is increasing its 2017 coal sales guidance to a range of 25.6 million to 27.6 million tons from what was 26 million tons previously. The increase in sales guidance is supported by higher natural gas prices and more normal coal inventory levels, which has helped improve demand from domestic power plant customers. Based on the updated guidance range, an approximately 95% of 2017 sales are contracted and 65% of 2018 sales are contracted.

With regards to the met coal kicker, CONSOL conservatively forecast around $15 million to $20 million in EBITDA associated with the 2017 Buchanan royalty. We raised the bottom end of the previous guidance since we see strong benchmark pricing -- met pricing and our royalty continues to remain in the money. Over the past 2 quarters, we have captured approximately $15 million.

Now turning over to the macro front. We remain confident in favorable supply and demand conditions for 2017 and into 2018. On Slide 15, we showed evidence that the market is undersupplied, which could be as much as 3 Bcf per day. Normalizing for heating degree days, storage withdrawals were stronger than expected, leaving inventory at average levels. Couple this with higher demand and relatively flat first-half of '17 Appalachian production creates a more bullish outlook heading into 2018. We are also encouraged by the recent progress in major pipeline projects, including Rover, as highlighted on Slide 16. As we stated recently, we expect basis to continue to contract longer-term and average around $0.10 to $0.15 or in line with the variable cost of transportation out of the basin.

We've improved our open natural gas basis outlook for 2017, '18 by around $0.28 per Mcf driven primarily by shifting gas away from certain higher-basin differential areas along with securing favorable firm sales contracts.

Now let's talk about marketing and hedging. We take a portfolio approach to market our E&P products given the high risk of overproduction that causes 1 method of shipment to come in and out of favor. This means we will use existing low-cost FT along with other operator's existing FT and firm sales or physical sales and then supplement with the hedge book. This enables us to be flexible on how much and where we produce, which is very important with the disruption of the dry Utica coming into play. We do not want stranded high-cost FT. We recently put greater emphasis on physical sales which cover and lock in prices in often premium and illiquid markets. This aspect represents about 11% of our forward marketing book. In first quarter specifically, CONSOL completed 2 large volume contracts on the East Tennessee system. The pricing structures for these deals provide value above pool sales on [Colombian] gas transmission, where much of the gas flowed prior to certain system enhancements. Furthermore, both deals utilize customers firm transformation capacity at no cost to CONSOL, thereby allowing CONSOL to forgo the renewal of certain of its firm transportation obligations on the East Tennessee system.

Now while we're confident micro dynamics going forward, we continue to derisk revenues with our systematic hedge program. In the first quarter, CONSOL added NYMEX, a gas hedges of 153.7 Bcf for 2018 to 2021, and 253.5 Bcf of basis hedges for 2017 to 2021. As shown in Slide 11, approximately 74% of our guided 2017 production is completely hedged on both NYMEX and basis. We're also more than 50% hedged for 2018 and we're able to lock in some favorable rates during our recent runoff in both NYMEX and basis.

Let's talk about the balance sheet leverage and liquidity. After surpassing our 18-month free capital plan at the end of 2016, and as executing our deleveraging plan for this year, our balance sheet repair is nearly complete. This enables optionality to use free cash flow to include things like stock repurchases, asset purchases as well as increased drilling. All of our efforts to lock in revenue increased margins helped drive our #1 capital allocation initiative so far for using leverage. To that end, we did repurchase about 100 million of the 2022 bonds in the first quarter at an average price of $98.54. This debt repurchase was done with all organic free cash flow, and we also generated $117 million in total free cash flow.

At the same time, CONSOL was able to maintain liquidity of roughly about $2 billion, similar to year-end levels. Based on expected organic free cash flow and our current estimate of asset sales of the year and our tax refund, we expect to reach our target-to-leverage ratio before year end.

In summary, we continue to focus on further strengthening and our already strong balance sheet. We remain committed to making prudent capital allocation decisions and our goal is to finalize the coal and E&P separation in 2017. Once we split, we will continue to differentiate ourselves by being able to grow and generate free cash flow. As Nick stated, 2017 will be year 2 in this regard.

With that, I'll turn it over to Tim.

Thanks, Dave, and good morning, everyone. We're very focused on driving the rate of change within our organization and have tackled another meaningful step change in drilling and completion efficiencies and how we manage production from our wells. In the quarter, we continued down a path of continuous improvement, highlighted primarily by reduced cycle times and optimized type curves from enhancements to our production protocols in certain areas. This has enabled us to improve our capital efficiency, increase our production and drive our NAV higher. We continue to drive down the correlation between production growth, rig count and TIL count, which will have the benefit of canceling out any inflation pressures from the service industry. Just to highlight this, our quarterly costs are lower year-over-year and will continue to be driven lower throughout 2017 as production increases. We will continue to run 2 drilling rigs and 2 frack crews throughout the year and our capital efficiency will more than offset any service cost inflation.

These latest operational efficiency improvements have outpaced even our own expectations. As discussed on past calls, our improvements have been significant and we have shown that it is continuous and sustainable. In fact, our rate of improvement may be greater now than it has been at any time over the last several years. So how do we continue to make such significant step changes, particularly while shifting to the more challenging deep dry Utica? The advancement of our model-based approach during the period of inactivity in late 2015 and early 2016 allowed us to evaluate variances in rock properties and operational techniques, so we can now quickly determine if a change is NAV accretive and instantly implement it in our operations, thus seeing immediate results.

It seems a little counterintuitive to what normally happens but we were able to accelerate the learning curve during a period of inactivity. You can see it in our results this quarter as we're improving faster than ever.

So a quick operations update. We drilled 9 wells in the past quarter: 7 dry Utica wells in Monroe County, Ohio and 2 Marcellus wells in Washington County, PA. For 1 of the Marcellus wells, our team achieved an Appalachian Marcellus drilling record of 7,380 feet drilled in 24-hour period on our Morris 30B well in Washington County, PA. In the quarter, drilling efficiency, or days per 1,000-foot of lateral improved 18% compared to 2016, helping reduce our cost per lateral foot by 11%. In Monroe County, Ohio, the dry Utica wells averaged approximately 9,900 lateral feet while averaging 21.5 drilling days per well, compared to 24 drilling days per well during the fourth quarter of 2016. At the current pace, a single rig could drill 16 dry Utica shale wells per year with 10,000-foot laterals, which is a 14% improvement compared to the fourth quarter of 2016.

Drilling costs for the dry Utica in Monroe County have dropped from $384 per lateral foot in the fourth quarter of '16 to $351 per lateral foot this quarter and we expect further improvement in future costs. When you include completion costs, which have increased some due to design changes in proppant loading and proppant type, our Monroe County dry Utica well costs are now around $9 million for a 9,000-foot lateral, which compares to $9.6 million just 8 wells ago. We recently TD the Acan's 5M, our first offset to the Gaut 4H well in the Westmoreland County, PA, in the deep dry Utica. From a drilling standpoint, we have successfully drilled the Aikens well in a fraction of the time it took to drill the Gaut well. Specifically, it took us 38 days to TD the Aiken's well, compared to 167 days to drill the Gaut well.

Previously, we have stated that it would take us 5 to 7 wells to get our cost under $15 million. With the improvement seen on the current well and assuming completion operations go as planned, there's a clear path to a sub $12.5 million deep dry Utica well in the next 2 wells. Again, this highlights our tremendous rate of change. Results like this are likely to accelerate our shifting focus from Marcellus to the dry Utica, fast tracking the Utica development planning process and its infrastructure buildout options.

Shifting to completion activity. We utilized 3 frack crews in the quarter and finished completion operations in Allegheny County, Pennsylvania on the ACAA1 pad, which contains 6 Marcellus wells, as well as 1 Burkett and 1 Rhinestreet well. Our model-based design -- frack design optimization and improved logistics resulted in the company of fracking, on average, 12,045 feet per day compared to 800 feet per day in 2016. Operating at this pace with pads drilled and ready to frack, our frack crew can frack 46 Marcellus wells per year with an average lateral length of 8,000 feet.

Total completion cost for the 8 Marcellus wells fracked in the first quarter were $348 per lateral foot, which is flat to our unit costs for 2016 Marcellus completions and a 6% increase from the last wells fracked in 2016, which were in the third quarter. While we continue to see excellent production response from increased proppant loading and pumping nearly 600,000 pounds of proppant per stage, we are still able to offset service cost increases through gains and operational efficiencies.

On peak days, we were able to frack 11 stages per day, with many days exceeding 10 stages per day and unloading 130 sand trucks in a 24 hour period. 3 of the Marcellus wells retuned in line in the quarter with the remaining 5 wells carrying over into the second quarter.

Now, shifting to production. Our quarterly production was 95 Bcfe or an average daily production of 1.056 Bcf per day. This is a quarter-over-quarter decline from the fourth quarter, which was 101.3 Bcfe or average daily production of 1.101 Bcf per day. Even though Marcellus volumes increased during the quarter, we saw a decline in our Utica production, which was the main driver of the overall production decline in the quarter.

Now this is important. If you remember, last quarter, I laid out a development cadence for the year and said that we didn't expect any new wells to be turned-in-line until the very end of March, or early April, and that the Monroe County wells would not come online until the end of May. So the decline in the quarter is not unexpected and is driven by natural declines and the timing of when wells are getting turned-in-line. However, the decline was slightly accentuated to do some temporary shut-ins, specifically, we temporarily shut in a flowing Monroe County pad in order to frack an adjacent well and we temporarily shut in the Gaut well to install tubing. That said, we expect volumes to grow year-over-year in 2017, and the Utica production to continue to become a larger percentage of the production mix, sooner rather than later as Monroe County gets further developed, and the results from the Aikens pushes us further into the deep dry Utica development.

I'd like to spend the remaining time talking about how we further refined our production protocol and how it will result in increased production in 2017 and 2018, at the same capital levels we announced last quarter. There are 2 specific fields where we have adjusted our production protocol: one is the Morris Field, which has Marcellus production Greene County, PA; and the others is our dry Utica, Switz field in Monroe County, Ohio. You can see an illustration on Slide 8, highlighting the change that we continue to refine how we are flowing back our wells, which ultimately is changing in the shape of the type curve. We have been advocates of flowing the wells back under constraint conditions for a longer period of time so this is nothing new, but more so, a modification due to a breakthrough and our understanding of reservoir compressibility tailored to specific geologic areas.

Further production improvements are being driven by optimizing stage lengths, diversion techniques, and proppant loading. For the Monroe County switch wells, we've also optimized inter-lateral spacing. All of these modifications have resulted in a substantial production forecast increase while spending no additional dollars from the previously announced capital budgets for 2017 and 2018 of $555 million and $600 million, respectively.

So how have all the cycle time improvements and production optimization changes impacted capital intensity moving forward? If we think in terms of maintenance and production capital, to hold production flat, we expect it to further improve. More specifically, at our December Analyst Day, we talked about maintenance capital being $250 million to $300 million to hold 395 Bcfe flat. With some of the improvements and optimization changes that we've made, maintenance and production capital is near the low end of that range at $265 million to hold 395 Bcfe flat.

With that, I'll turn it back over to Tyler.

Thanks, Dan. This concludes our prepared remarks. Nick, can you please open the line up for questions at this time?

(Operator Instructions) First question today comes from the line of Joe Allman with FBR.

Do you have any comments on CONE in light of the NBL off stream asset sale announcement this morning? Do you have any preferential rights there? And would you have an interest in buying NBL's interest if any were available? And is there any value impact on CONE based on this change in ownership?

Joe, I think that looking at it as an owner in CONE, the announcement today should be viewed as a bullish indicator. And the reason we say that is, it's -- call it, roughly half of the acreage dedication that sits there at CONE today has changed ownership, and it's now in the hands of someone that -- I'm assuming has plans to develop it and CONE is looking forward to working with a new customers. So, from a growth perspective and then what that means for distributions and what not, I think that's positive news. Beyond that, I really can't comment other than what you've read and I've read out there in the public space.

Your next question comes from the line of Holly Stewart with Scotia Howard Weil.

Maybe the first question, just strategically, Nick, you listed kind of the -- all the strategic options, the 3 strategic options that you're looking at, and then Dave, I think you hit on the kind of hitting the leverage target of 2.5x. Should we expect some of these levers to start being pulled before or after your decision of separation? Or that -- how do we think about the 2 being linked?

I think the ability to allocate capital, across either increased activity set on the E&P side or share count reduction, additional debt reduction or acreage acquisition, are really -- doesn't so much come down to what and when we decide to do with splitting the 2 segments of coal and E&P. I think it's more driven by getting that leverage ratio down to the mid- to the low 2s. And that should be, again, something that happens sooner within 2017 as supposed to later.

Yes. And I would just add that the coal separation can only enhance probably our flexibility.

Perfect. And then, I don't know if Don would take this one, but just on the marketing portfolio, you mentioned some of the stuff that you've done on East Tennessee, just some color there in terms of letting the FT rolloff those sales contracts you've done. I'm assuming that looks like the pie has shifted a little bit maybe due to the -- that East Tennessee firm transport. And then maybe an additional one to that, where does Nexus kind of fall into those pie numbers for '17, '18?

Well, Holly, we've got the -- with the Nexus, it looks like there's potentially a delay there, although they're still saying it will be in service by the end of '17, but looking more and more like there will be a delay. And we do have a bit of our FT on Nexus. But we continue to push to -- for a balanced FT book that keeps our cost down. We've been able to release some capacity that we no longer need and move it off the books, but we'll continue working down that path to keep the FT under that $0.30 target that we've laid out over the last several quarters.

I think it's our ability to be able to sculpt the transportation aspect and where we ship our gas, without having to have a very rigid FT aspect of it. We'll allow our existing FT owner to be able to optimize his own book as opposed to us trying to fill-in a whole bunch of production. So it just allows us to then to not strand {HEF granted FT} or open FT and enable an existing FTR to be able to make a win-win between both sides.

Okay. Maybe just to make sure we understand, you've essentially released some FT on East Tennessee, but you've entered into some firm sales contracts on that same line?

Correct.

(Operator Instructions) And we will go to the line of Neal Dingmann with SunTrust.

Nick, I think a question maybe for you or David, just real quick on the asset sales. Did that include any of the -- or maybe for David, any of the existing minerals? And if not, any change in plans for the minerals that are associated with all those leases in that place?

Yes. The -- one of the asset sales does have some fee in there as well, yes. So, which enhance the value that we're getting. And as far as the second question, are we looking to do anything on our fee mineral position, in general, which is fairly large? I would just say, if we do, we'll announce for you, if we do something.

Okay. And then maybe a question for Tim just on that slide -- Tim, that's Slide 8, you referred to, I really like those obviously, those revised type curves are flat in -- the production hanging on earlier. With that, I mean, does that change your EUR estimate? I didn't notice but has -- but certainly appears those curves by flattening or improving, would that mean your EUR's would improve or have improved as well?

Right now, we haven't changed the EURs on those wells, we've changed the shape of the curve by holding production flat for a longer period of time, and have adjusted the decline to be factored on our decline once the well starts to decline. So we have not changed the EURs at this point.

Okay, and then, Tim, just one last one on that slide -- the following Slide 5, slide -- now you talked about on the Gaut, kind of installing the tubing. Guess my question is just more broadly, Tim, when you guys look at some of these wells, like the Gaut or some of these other existing ones, are there going to be continuing to be a number of things like installed tubing or things like that, that you can do to continue to boost that line pressure? It certainly a noticeable increase on this one, so I'm just wondering are there other things like that of that we should assume you can do for relatively minimal expense going forward?

No, the tubing install is a -- it's an expected, anticipated and managed step. We watch our critical velocities and ability to unload wells and keep the gas flowing and install the tubing when it's appropriate. But obviously, there's opportunities to put wells on compression and things like that where we can continue to manage the pressure drawdown.

We do have a follow-up question from Holly Stewart.

Just maybe one more because you lay out the turned in lines in '18, which shifts a little bit more to the Utica? But I guess, what do you need to see to make this a bigger shift in 2018, towards the Utica?

Well I think that's -- it's really being driven by results, Holly. As I said, we just TD the Aikens well, which is an offset to the Gaut. And so far everything up in that area has met our expectations, and as more and more results come in, we will -- we'll push -- continue our push towards the Utica. Where laying out additional wells and we're working on our development plans as we move forward. So I think just continued results as we've seen and continue push to get more wells drilled and turned-in-line.

With that, speakers, there are no further questions in queue.

Okay, great. Thank you, everyone for joining us this morning. We look forward to speaking with you again next quarter. Thank you.

Ladies and gentlemen, today's conference call was recorded. It will be available for replay beginning at 12:30 p.m. today and running through May 9. You may access the AT&T playback service at any time of day by dialing 1 (800) 475-6701 or internationally, (320) 365-3844 with an access code of 406259. That does conclude our conference for today, we thank you for your participation and for using the AT&T Executive Teleconference Service. You may now disconnect.