Antero Resources Corporation

Greetings and welcome to the Antero Resources first quarter 2019 earnings call. At this time, all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Michael Kennedy, Senior Vice President of Finance. Thank you. You may begin.

Thank you for joining us for Entero's first quarter 2019 investor conference call. We'll spend a few minutes going through the financial and operational highlights, and then we'll open it up for Q&A. I'd also like to direct you to the homepage of our new website at www.enteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Before we start our comments, I would like to first remind you that during this call, Intero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Intero and are subject to a number of risks and uncertainties, many of which are beyond Intero's control. Actual outcomes and results could materially differ from what is expressed, implied, or forecast in such statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman and CEO, and Glenn Warren, President and CFO. I will now turn the call over to Paul.

Thank you, Mike, and thank you to everyone for listening to the call today. In my comments, I'm going to provide an update on our firm transportation portfolio, both for natural gas and natural gas liquids, then discuss 2019 operations and round out my comments by providing color on our operational execution during the quarter. Glenn will then briefly touch on the implications of the deconsolidation event as a result of the simplification transaction that closed in March and highlight our first quarter financial achievements, including strong realized pricing and further leverage reduction. He will finish with a discussion of Antero's strong position and outlook for the future. Let's begin with a discussion on our firm transportation position, both for natural gas and natural gas liquids. I'll first touch on the natural gas liquids firm transportation, given the recent startup of Mariner East 2. As outlined on slide 3, titled Inflection Point in NGL Marketing and Pricing, we began shipping volumes for the first time in February through our commitment on the Mariner East 2 pipeline a pipeline that transports NGL volumes from fractionators in southwest Appalachia to the Marcus Hook facility in Philadelphia for exports into the global markets. We have 50,000 barrels a day of propane and butane capacity contracted on the pipeline, which equates to about one-third of the available capacity on ME2 today. As the largest shipper on ME2 and with approximately 50% of our NGL production being sold into premium international markets today, we are well-positioned to deliver peer-leading NGL price realizations going forward. As you can see from the table on the left-hand side of the page, our NGL realizations increased from 52% of WTI before ME2 was in service in January, to an average of 61% of WTI after it came in service. This substantial uplift boosted cash flow by approximately $20 million during the first quarter. This uplift is particularly impressive when you consider that this occurred during a seasonally strong quarter when in-basin pricing is typically strong. As you can see from the swooping arrows on the map in the middle of slide three, we exported 29% of our C3 plus NGLs in the first quarter, but expect to export 50% for the full year as export volumes ramped up to this level through the first quarter. Although the relationship between Bellevue NGL prices and WTI crude prices has disconnected a bit in recent months, We expect our C3 plus NGL prices to be approximately $4 per barrel higher on an absolute basis compared to our original guidance back in January. This increase in expected NGL realizations is due to the strength in WTI crude prices and also strong international demand for NGL products out of Marcus Hook, the terminal there. In recent months, we have seen significant spreads between international pricing and Mont Belvieu pricing, as you can see on slide four, titled Attractive International Spreads. Our meaningful exposure to international NGL prices allowed us to benefit from this spread during the quarter, and we expect that diversification will benefit us throughout the year. This provides yet another example of how our diversified transportation portfolio reduces both pricing and operational risk around any one particular geographic area or pricing index. On the ethane front, volumes are expected to pick up slightly with the restart of Mariner East 1 last week. This pipeline had been shut down for the majority of the first quarter. Though we were able to reject this volume and sell the ethane as gas value during the quarter, this resulted in 50 million cubic feet equivalent per day, less production during the first quarter on a natural gas equivalent basis. But importantly, we have the flexibility to reject any remaining ethane in the stream above our contracted volumes and volumes required to meet pipeline specifications and sell the ethane at natural gas value to maximize overall profitability and cash flow. Based on current strip pricing for the remainder of 2019, we intend to continue recovering ethane only at levels necessary to fulfill ethane contracts and meet pipeline specs. For the full year of 2019, we expect to recover total ethane volumes in the range of 38,000 to 42,000 barrels a day, down from a previously guided range of 48,000 to 52,000 barrels per day that we set in January of 2019. To the extent that ethane prices improved to levels that support ethane recovery economics, we would elect, of course, to recover additional ethane volumes. Shifting gears to discuss our natural gas firm transportation position and the long-term benefit it provides, I'll direct you to slide five titled, Firm Transportation Portfolio is a Strategic Advantage. With the entirety of our committed firm transport now in service, you can see the significant visibility that our FT portfolio provides us with respect to our long-term development plan. For 2019, we are forecasting natural gas price realizations at a $0.15 to $0.20 premium to NYMEX and expect to continue realizing premiums to NYMEX in the coming years. Unlike many of our peers that are relying on local basis to remain tight in order to develop their asset base over the long term, We have significant visibility and confidence as it relates to the realized price we will receive due to our transport portfolio to premium markets. This enables us to make longer-term decisions about the business and focus on what creates long-term value for our shareholders. While we are not fully utilizing the pipelines today, we expect our net marketing expense to decline each subsequent quarter moving forward with the first quarter of 2019 being our peak level. This marketing expense will be virtually eliminated by 2022 when we expect to fill our premium firm transportation. It is important to note that our net marketing expense is offset by our industry-leading hedge position, which will deliver 20 cents per MCFE in 2019 at strip pricing, along with the benefits that our FT portfolio provides through delivering volumes into premium price markets. Among these premium markets is the Gulf Coast, which is illustrated in purple on the chart indicating our peer-leading 2.1 BCF a day of capacity into that market. This provides us with tremendous leverage to the growing LNG export market, and the NYMEX-based pricing typically associated with long-term LNG supply contracts. We currently supply 630 million cubic feet a day total, and by the end of 2019, we will be supplying 700 million cubic feet a day to LNG facilities for export, making us a top supplier to U.S. LNG markets. LNG markets are expected to increase by 3.9 BCF a day in 2019, as illustrated on slide number six, titled Growing LNG Market. There are also multiple second wave projects seeking FID this year. Our significant firm transport capacity into the Gulf Coast region provides a tremendous opportunity for us to benefit from this robust growth. We expect our firm transportation portfolio to become increasingly valuable as LNG players look to secure long-term supply agreements with strong counterparties who have confidence in their drilling inventory over multiple decades. Antero has the production base, the drilling inventory depth and quality, the transport portfolio, and the balance sheet to be a very strong player in the LNG supply business. Now to briefly touch on our 2019 development and capital plan. We placed 23 wells to sales during the first quarter, all on our liquids-rich Marcellus acreage. We drilled 36 wells during the first quarter with an average lateral length of 10,000 feet. In the second quarter, we plan to place 41 wells to sales, including 23 that were placed to sales in April. This increase in sequential activity from the first quarter to the second quarter, with a focus on liquids, keeps us on track to achieve our full year average production guidance. Turning to our capital plan, we recently reduced our rig count and completion crews by one each. We now expect to run four drilling rigs and three completion crews on average through the remainder of 2019. As a result of the reduced rig and completion crew count for the remainder of 2019, we expect drilling and completion CapEx and the second and third quarters of 2019 to be in the low $300 million area. Further, we are reducing our full-year 2019 CapEx guidance to $1.3 billion to $1.375 billion, the low end of our prior range. Before I turn it over to Glenn, I'd like to discuss the many positive advancements we are seeing on the operational front. Turning to slide seven, titled Drilling and Completion Efficiencies Continue, I'll jump to the top right quadrant of this page and highlight that we continue to push the average lateral feet drilled per day higher. We drilled an average of 5,300 lateral feet per day in the quarter, the highest quarterly rate in company history, representing a 14% increase in lateral footage performance compared to 2018. Most impressively, we recently set what we believe to be a world record in the category of drilling lateral feet in 24 hours, where we drilled a horizontal well and drilled sideways 9,184 feet in 24 hours on the Antero Hayhurst Unit 2H well, which is in our rich gas play fairway. While we're very proud of the record set here, we're also very pleased with the continued and consistent move higher in average lateral feet drilled per day. Completion stages per day in the Marcellus averaged 5.3 stages per day for the full quarter, higher than our overall 2018 average. This is a noteworthy number as the first quarter is typically the most challenging from a seasonal standpoint due to winter conditions. Given our full year 2019 budget, which assumes 5.2 stages per day, we feel very good about our continued efficiencies leading to lower well costs throughout the year. An increase of one additional stage per day does result in about $200,000 of savings per well, so it's important to us. We continue to be focused on operational efficiencies that will drive well cost lower. Progress that we have exhibited already in 2019 gives us confidence in achieving our full year production targets with spending at the low end of our capital guidance range. We've achieved significant scale and product diversity as the largest NGL producer and the fourth largest natural gas producer. And we have a firm transportation portfolio structured to deliver best-in-class price realizations for our products, even in a difficult operating environment. These attributes, combined with our peer leading core drilling inventory, position us to deliver attractive long-term returns to our shareholders for many years to come. With that, I'll turn it over to Glenn for his comments.

Thank you, Paul. In my comments today, I will discuss our first quarter financial results, provide additional color on the uplift to our NGL price realizations with the startup of the ME2 pipeline, and conclude with comments around our competitive advantage that we have built through our large-scale liquids inventory, product diversity, and exposure to the growing demand markets for both liquids and natural gas. This provides us with multiple ways to win going forward. Before I get into these topics, I did want to provide a reminder that with the closing of the midstream simplification transaction in March, AR will no longer consolidate AM on its GAAP financial statements, but will rather record its interest in AM through the equity method of accounting. We are excited about this change as we believe it will provide several benefits. First, it improves the transparency and disclosure for AR on a standalone E&P basis. This will enable investors to more easily compare and contrast AR with its peers. Importantly, this transition will minimize future inconsistencies among analysts, investors, and financial screening services on AR's leverage, EBITDAX, capital, and free cash flow, just to name a few, and therefore significantly simplify the story. As you can see on slide number eight, Our consolidated, deconsolidated metrics are extremely attractive with leverage at 2.1 times and our enterprise value to EBITDAX at just 2.8 times on a hedged basis. Since the transaction closed mid-quarter, our first quarter 2019 financial statements still included consolidation up through the closing date on March 12th. However, all subsequent quarters will treat the Antero midstream ownership through the equity method of accounting. Now moving on to first quarter results. During the quarter net production averaged 3.1 BCFE per day, delivering 30% year-over-year growth, including 148,000 barrels a day of liquids. Liquids production increased 44% year-over-year, reflecting a continued emphasis on developing our liquids-rich acreage. Net liquids production included over 11,000 barrels a day of oil, approximately 98,000 barrels a day of C3 plus NGLs and 39,000 barrels a day of ethane. During the first quarter, Antero's realized natural gas price was $3.30 per MCF before hedges, representing a 15 cents per MCF premium to the average NYMEX Henry Hub price. We expect to continue delivering peer leading natural gas price realizations in 2019. as reflected in our 2019 guidance for natural gas realizations before hedges at a 15 to 20 cent per MCF premium to Henry Hub. Our natural gas portfolio, hedge portfolio, as shown on slide number nine, protects 100% of 2019 and 55 to 60% of 2020 targeted natural gas production with an average floor of $3 per MMBTU. It is notable that we remain the only publicly traded U.S. producer that is 100% hedged on expected natural gas production in 2019 with an average floor of $2.77 per MMBTU for the remainder of 2019, the last three quarters of 2019. Moving on to liquids pricing during the quarter, as Paul discussed, the first quarter of 2019 was an important inflection point for Antero Resources as the Mariner East II pipeline went into service on January 29th, giving us access to premium priced global LPG prices during February and March. We hold about one-third of the current 150,000 barrels a day of throughput on ME2 through our 50,000 barrel a day commitment, making us the largest shipper on the pipeline. We realized an unhedged average C3 plus price of $31.63 per barrel for the quarter, an increase over the prior period despite softness and Mount Bellevue benchmark prices. Further, our average realized C3 plus NGL price during February and March, once ME2 was in service, increased to $34.70 per barrel, representing 61% of WTI prices. We actually received a 17 cents per gallon premium to Mount Bellevue prices at Marcus Hook for propane and butane that was exported in February and March. That is illustrated once again back on slide number three. We expect our realized NGL prices to strengthen on a relative basis to Mount Bellevue with ME2 now in service. Although domestic NGL prices did not fully participate in the rally seen in crude oil prices in recent months, international pricing has remained strong. Our significant volumes on ME2 give us the highest exposure to international LPG markets, which positions us to deliver peer leading NGL price realizations going forward. Further, the approximately 150,000 barrel a day flowing on ME2 evacuates almost 40% of the basin's NGL production, which is already and is expected to continue to improve in basin domestic related pricing. where we sell about 50% of our overall C3 plus NGL volumes today. Moving on to slide number 10, titled Deleveraging Through Commodity Price Volatility, our balance sheet is in the strongest position in our company's history. We have reduced absolute debt by over $800 million over the last few years, lowering leverage to 2.1 times as of March 31st. During the first quarter, we reduced borrowings by $360 million, resulting in only $50 million drawn on our $2.5 billion credit facility. This was achieved with proceeds from the midstream simplification process and the remainder from $68 million of free cash flow generated during the first quarter. Our borrowing base was reaffirmed at $4.5 billion during the spring redetermination with unchanged commitments at $2.5 billion. This highlights the strength of our asset base and the depth and resilience of our drilling inventory. Before turning the call over to questions, I would like to comment on our current competitive positioning and outlook for the next several years. We have built our business to excel in an ever-changing macro backdrop. We are seeing this play out in our cash flow generated and projections looking ahead. Despite a reduction in natural gas prices throughout the year to the $2.50 spot levels we see today, and historically low Mont Belvieu NGL prices relative to WTI pricing, our material exposure to the international NGL markets has provided a valuable offset that enables us to maintain our production growth targets while also spending within projected cash flow. Looking ahead, we continue to target at least 10% growth in production while spending within cash flow, as demonstrated on slide number 11, titled Attractive Growth Outlook with Disciplined Spending, We expect to deliver this growth in 2020 and beyond with modest capital increases that correspond to our increasing cash flow. Slide number 12, titled Maintenance Capital and Decline Rate Projections, provides further detail on our future capital spend needed to keep production flat. That's not to say that we would do that. As we previously disclosed, 2019 maintenance capex is $840 million, with the remaining $460 million plus of capital spend supporting our 10% growth in 2020. As shown in the chart on the left-hand side of the slide, our base decline rate continues to move lower each subsequent year, as does our maintenance capex, assuming flat 3.2 BCFE a day of production. This simply illustrates that maintenance capital is a function of base decline rate, which is in turn a function of production growth over the previous 12 months. And you can see our base decline in the appendix. There's a slide there. In summary, please turn to the summary slide number 13. We're in the best operational and financial position in our company history. We remain focused on maintaining a strong balance sheet reflected by our debt reduction, both on an absolute basis and relative basis, with leverage down to 2.1 times during the quarter. We have significant scale and product diversity as the largest NGL producer and the fourth largest natural gas producer in the US. The natural gas firm transportation portfolio that we've built allows us to sell into premium markets in the Midwest and on the Gulf Coast with very minimal exposure to local pricing. Our 2.1 BCF a day of firm transport to the Gulf Coast gives us the largest exposure to growing LNG export demand, where we are among the largest suppliers It's $700 million a day by year end this year. On the liquid side, we expect to sell 50% of our NGLs into the global markets in 2019, diversifying our liquids pricing exposure and providing yet another link to premium price realizations. In short, we have built a business with many ways to win under changing market conditions. With that, I'll now turn the call over to the operator for questions.

Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you'd like to move your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please while we poll for questions. Our first question comes from the line of Jane Trusenko with Stiefel. Please proceed with your question.

Good morning. My first question is on NGL fundamentals. I'm curious if you could share your thoughts on Mount Bellevue pricing outlook and maybe on international demand and how it's going to evolve during 2019. Thanks.

Jane, let me turn the call over to Dave Catalongo, our Vice President of NGLs and International Markets.

Yeah, Jane, we saw a fair amount of weakness in Mount Bellevue in the first quarter as a result of some of the challenges they had with fog that they see down there seasonally, as well as a fire that occurred at the ITC terminal on the Houston Ship Channel. But in addition to that, we've started to see a limit on the amount of production that's able to get out of the caverns to the water, and that is really dependent on some expansions of terminals there. There are a couple of projects in the third quarter from a few of the midstream players down there that will increase their ability to access those markets. And so at that point in time, we would see some support for Montbelvi pricing coming on then. We do continue to see growth internationally in the petrochemical market, in particular in Asia, although there are a couple of PDH projects slated for Northwest Europe and growing ResCom demand coming from Southeast Asia as well as India that has been supportive to international pricing. So All those things lined up together to allow us to have a very strong winter and spring so far on marineries, too.

Got it. So it would be fair to say that you would see that you expect to see NGL fundamentals to improve from this point on in terms of domestic NGL pricing, I would say, right?

We do and in particular I want to mention as well the ethane market just with some of the new petrochemical facilities that are coming online here as we speak and three additional ones later this year that will significantly improve the demand for ethane down the Gulf Coast complex.

Okay, got it. My second question is on Ohio UTECA. Could you please remind us how you view this asset in terms of capital allocation and in terms of production trajectory going forward?

Yeah, we like our Ohio Utica project both on the rich side as NGLs have gotten stronger. Our rich gas trend has become more economic and also in the dry gas areas where we have We have accumulated acreage in very good reservoir quality areas. So we like the project quite well, but it still doesn't compete with Marcellus, and so that is our focus, that still the Marcellus economics are better. Therefore, our capital is almost 100% dedicated to the Marcellus at this time, but very much like the Utica still.

Okay, but should we think about Utica as a kind of flat production trajectory, or will it be declining?

It'll probably be flattish, I would say, that we drill a half a pad or a full pad every year, and so that can keep production flat.

Got it. Thanks a lot.

Thank you.

Thank you. Our next question comes from the line of Holly Stewart with Scotia Howard Wheels. Please proceed with your question. Good morning, gentlemen.

Good morning.

Maybe just first let's start off on the sort of production guidance wedge. I would call it the, you know, 10% at 50 and 285 and then 15% at 65 and 315. I know you guys are noting in the slides like likely somewhere in between just given the markets. I think probably until this week we would have thought that crude would be at the high end and gas at the low. So maybe, Glenn, could you just make some comments around, you know, if this scenario were to play out, sort of how you guys are thinking about that wedge and sort of the production going forward?

Well, as Dave mentioned, I think we feel really good about the NGL markets and think that that's going to continue to strengthen. And so that makes up for softness in gas in the near term. We still are firm believers in gas over the medium and longer term. We just need to get through this shoulder season and see how the injections look through the summertime and see what kind of summer weather we have as well. But we're still on that 10% growth line for now. You don't see us accelerating capital just due to oil prices and NGL prices being higher. We're very comfortable with that 10% line for now, and we'll evaluate that really every quarter as we go forward, Holly.

Okay, that's great. And then maybe I thought slide 19 did a good job of just the waterfall of well costs and the Marcellus. Could you just maybe provide a little bit of color around the inflation that you have seen and then some of those renegotiated completion contracts?

Yeah.

we do do see, uh, certainly pressure. We do a lot of water hauling, of course, from, uh, from the well sites, both flow back water and produced water. And so there's, there has been pressure on, uh, trucking costs, especially driver costs, but, uh, we've been able to trim back and, uh, use fewer trucks as we've gotten more efficient in call outs and so on. So yes, there is some, uh, pressure there, but, uh, On the other hand, the renegotiation of certain contracts like the self-sourcing have been very beneficial. Right now, we are self-sourcing at least 70, approaching 80% of our sand needs for this year. It's working out quite well. We're contracted with suppliers that can actually barge up the Ohio River. which is quite a cost savings from railing from the traditional northern white trends. We save quite a bit there, and we have staging facilities on the Ohio River right next to our acreage. We do have, in case that there are ice dams and so on on the Ohio in the winter, we do have quite a good amount of sand set aside to fall on if there are any logistical hitches. So That has really reduced our sand costs, which are significant, by about a third so far and expect to see that translate through. So I'm talking about not only the sand itself but the last mile. So we're getting those costs down, and those add up to several hundred thousand dollars per well. So seeing those efficiencies with bigger pads, as you know, we can – get off more stages a day just to the logistics on the pad. So a lot of efficiencies that are helping to bring our well cost down.

That's great. Thanks, guys.

Thank you.

Thank you. Once again, as a final reminder, if you would like to ask a question, please press star 1 on your telephone keypad. Our next question comes from the line of Sabash Chandra with Guggenheim Partners. Please proceed with your question.

Yeah, curious, a couple of things. Dropping the rig in the Marcellus through the balance of the year, is that something you could continue through 2020 while keeping the 10% CAGR, or do you anticipate bringing activity levels back up next year?

We expect to have a similar number of completions next year, but with a bit longer laterals on the completion front and probably drill a few more wells as well as we grow next year. So we expect to spend a little bit more capital next year, but not much. So I don't know. I'm not sure it's a full rig, but at least a half a rig more probably.

Okay. Is there an update? I think, Paul, you were mentioning anecdotally a number of places you're achieving cost savings. Is there a way to sort of phrase that on a dollar per foot or maybe some dollar per foot exit forecast for this year?

Well, you can see on slide 19, Subhash, that quantifies on a dollar per foot going from $0.95 million per thousand feet of lateral down to 0.93. Obviously, that's just around a 2% reduction. Continue to work on that to try and get it lower. It would be great as a target to get into the high 0.8s, and so we'll see where it goes. Naturally, the reason we dropped the rig in part is that we're just getting so much more efficient, so much faster, as we highlighted in our comments, on average, and Yeah, average lateral feet per day, as well as the record setters. Not only have we had the recent one above 9,000 feet, but we're drilling a number of them that are in the sevens and 8,000 feet per day. And so with that, you can accomplish that much more with much less drilling time. So, yeah, that would be our target, that if we're going to achieve at least 2% or so on that per footage cost, Where will it go from there? Well, we keep striving for twos and threes and four percents as we go forward. It's not over yet.

Yeah, right. Yeah, I wasn't clear if slide 19 was updated for the CapEx reduction that you talked about on the quarter. Yeah, it is. Yeah, got it. And then the slide on drilling D&C efficiencies, slide 7 shows – Utica results. Is there Utica activity underway?

Hi, Subhash. This is Mike. We do not have a drilling rig in the Utica, but we did have one completion crew there for part of the first quarter where we completed one pad. But there's no further activity throughout 2019. Okay. Got it.

And a final one. Just philosophically, where you stand on your plans for AM and using that as a source of funds?

Well, AM is obviously a great asset for AR, and we'll just see how that shakes out over time. We expect to see a lot of value improvement, price improvement at AM as it seasons here and gets added to some indices over the next few months. Very optimistic there, but no direct plans to do anything with that position at this point.

Okay. Thank you.

Thank you. Our next question is a follow-up from Jane Trezenko with Stifel. Please proceed with your question.

I have a natural gas macro question that I need to ask. I'm curious if you are seeing lower activity levels from privates in West Virginia, Marcellus, given where natural gas prices are, or do you think, like, we need to stay in that 250 range for a little bit longer to see the privates cut back?

I'm sorry, could you repeat that? Are you asking whether or not private equity backed – activity has slowed down?

Exactly.

Yeah. Yeah. You know, we're not seeing a lot of slowing yet, and I think that's something that we will see over the next year, whether that's Hainesville or Utica, Marcellus. So the privates have continued to be fairly active, and I think the last time we looked at it, the private equity-backed portfolio companies, they constituted maybe 40 percent of the rigs running on the gas side. And I think sometimes they are not under the same scrutiny as public companies and are probably drilling for other reasons than, you know, just direct well economics in some of these areas. So I think that would be a healthy development to see the private scale back on their drilling activity and completion activity, of course, in the dry gas place.

But you don't see it just yet, right? It seems to me like we need to see this weakness for a little bit longer before it translates in lower activity levels for private, right?

Price should drive that decision-making over time, you're right, but it's hard to predict.

Okay, okay, got it. And I wanted to ask a question, a follow-up. obviously you're making great progress in terms of capital efficiency and dropping rig without changing reducing the capex to the low end of the guidance without changing production outlook I'm just curious are there certain read-throughs from those efficiencies to 2020 let's say capex might not be as high as expected or something in that type of that action?

I think that's certainly possible. You know, we think the inflation is a non-issue today with services in our space, so that's good news. We think that's really been tamped down. The only inflation we've seen, as Paul mentioned, that sort of continued through last year was just the rates charged to, you know, incentivize truck drivers to move water, oil, you name it. But I think that's leveled out now, and activity is is flat to down in Appalachia, so that's all good news there. And the efficiencies are still running, as you heard. To get up to 5,300 feet a day on average in the lateral in the first quarter, that's great progress. So you need fewer and fewer rigs to generate the number of spuds that you want to get going each quarter. And then on the completion side, we think there's still lots of upside in terms of stages per day. And we saw... a little over five stages a day in the first quarter, which, as we said, is normally a fairly slow quarter due to winter logistics, and we didn't really have much problem with that this time. So we expect that to pick up throughout the year and into next year, and maybe a good target is to get up to eight stages a day or so here over the next year or two. So we still see lots of room for improvement there on the efficiency side.

Do you see laterals getting longer year over year? And in terms of prop and loadings, is it going to change next year?

Yeah, we have such a strong inventory that we have our program planned out for the next five or six years in terms of which specific laterals, which specific units we are going to drill. And they do get longer year by year. How much per year, if they're averaging, you know, 11,000 to 12,000 this year, they get out into the mid to high 13s over the next several years. But we have just found that it's more efficient in terms of cycle time and so on. That's a sweet spot in the 13,000, 14,000 foot range, a little longer than that. And there's just such delays in completing the wells. So we're happy with that. And what was the second part of your question again, Jane? Sorry.

Prop and intensity. How much scent you guys are using? Is it going to change or is it going to remain the same?

It will probably remain the same. We feel good about 2,000s. In some of our step-out areas, we sometimes go to 2,500 pounds per foot. But generally, we're happy in that scenario of 2,000 pounds per foot. Every now and again, we do 1,750 pilots to check that out. And so we continue to learn, but I'd say it has mostly stabilized around 2,000 pounds per foot.

That's very helpful. And the last question, if I may, on M&A, if you have, like any general pilot, comments about M&A activity in the basin?

Yeah, we do think you'll continue to see some consolidation over time in the basin, but not hearing of a whole lot of activity right now. I think there'll probably be some asset situations, maybe private equity backed first, but we keep an eye on that as well.

Awesome.

Thank you so much for taking my question.

Thank you.

Thank you. We have reached the end of our question and answer session. I would like to turn the floor back over to Mr. Kennedy for any closing remarks.

Thank you for joining us on the call today. If you have any further questions, please feel free to reach out to us. Thanks again.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.