Antero Resources Corp (AR) 2018 Q4 法說會逐字稿

Good day, and welcome to the Antero Resources' Fourth Quarter and Year-End 2018 Earnings Conference Call and Webcast. (Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to Mr. Michael Kennedy, Vice President of Finance and Head of Investor Relations. Please go ahead.

Thank you for joining us for Antero's fourth quarter 2018 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 would also like to direct you to the homepage of our new website at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call.

Before we start our comments, I'd like to first remind you that during this call, Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero'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 Glen Warren, President and CFO.

I will now turn the call over to Paul.

Thanks, Mike, and thank you to everyone for listening to the call today. In my comments, I'm going to review our 2018 development activity, including the cost efficiencies we have achieved and discuss our recently announced 2019 capital budget and flexible long-term development outlook. Glen will then highlight our fourth quarter and full year financial achievements and discuss the expected change in financial reporting to deconsolidate Antero Midstream from AR, following the simplification. Glen will also touch on our 2018 proved reserves and provide some additional color around our long-term outlook and firm transportation portfolio.

Let's begin by discussing the efficiency improvements we made during the quarter and throughout 2018. Once again, Antero set new operational records during the fourth quarter.

Looking at Slide #4 titled Drilling and Completion Efficiencies during the fourth quarter. Completion stages per day in the Marcellus set another company record for a full quarter, averaging 5.7 stages per day. For the full year of 2018, completion stages per day in the Marcellus averaged 5.2 stages per day, which was an increase of 1 full stage per day from the 2017 average of 4.2 stages per day. Looking at our 2019 budget, we are assuming 5.2 stages per day, so this is certainly an area we think we can outperform, resulting in additional well cost savings. To provide some detail on these savings, an increase of one additional stage per day would result in about $200,000 of savings per well.

Moving on to some of our recent operational results. During the fourth quarter, we turned to sales several outstanding Marcellus liquids-rich pads. One particular pad was a 10-well pad with an average lateral length of 9,700 feet and an average BTU of 1,230. This pad produced approximately 195 million cubic feet equivalent per day during the first 60 days or 19.5 million cubic feet equivalent per day per well. The liquids rate on this pad was nearly 10,100 barrels a day during the first 60 days, consisting of 1,400 barrels of oil, 5,700 barrels a day of C3+ NGLs and 3,000 barrels a day of recovered ethane, representing about a 25% ethane recovery.

Another strong data point from the quarter was from a well we completed in our highest BTU regime that was drilled with a lateral length of nearly 15,100 feet. This well produced a 60-day rate of nearly 29 million cubic feet equivalent per day, including approximately 2,100 barrels of total liquids. As we enter 2019, we like where we are positioned from both a scale and commodity diversification standpoint.

As illustrated on Slide #5 titled Antero's Balanced Position on the Commodity Spectrum, we are the largest NGL producer in the U.S. and the fifth largest natural gas producer. This scale across both commodities provides us with the ability to manage through commodity price volatility and prosper with any increase in either commodity. Antero holds 40% of the core undrilled liquids-rich locations in Appalachia, over 2.5x more than the closest competitor by our analysis. This extensive liquids inventory is a clear competitive advantage.

Now let's turn to our 2019 development plan and long-term outlook, which we announced on January 8. We are expecting annual production growth during 2019 in the range of 16% to 20% while spending within cash flow.

Slide #6 titled Disciplined Long-Term Development Plan highlights our production growth through 2023 under multiple commodity price scenarios, ranging from $50 to $65 per barrel WTI, and $2.85 to $3.15 per MMBtu NYMEX natural gas pricing. The important takeaway here is that Antero will remain flexible depending on the commodity price outlook. We will remain disciplined, spending within cash flow in a low case but have the ability to prudently grow production to maximize free cash flow if commodity prices improve, ultimately delivering an appropriate mix of return of capital to shareholders and further deleveraging.

To provide some more details on capital and our well costs, I'll point you to Slide #7 titled Path to 2019 Well Cost Efficiencies. On this page, you can see a bridge from our standalone Marcellus well cost when we entered 2018 to our target in 2019 for a 12,000-foot lateral. Entering 2018, our standalone Marcellus budgeted well costs were $950 per foot. As oil prices rose throughout the year, the well costs were impacted by 6% inflationary costs, primarily related to increases in water hauling costs and production facility expenses. We were able to primarily offset the inflation in 2018 with reduced sand cost through self-sourcing and overall completion costs through a 25% increase in stages per day and renegotiated contracts.

Our 2019 target of $930 per foot assumes savings from additional sand self-sourcing contracts, a further increase in stage efficiencies and optimized water handling as well as improvements at the Clearwater facility. Further, we expect the D&C capital cost reductions by multiple public operators, to date, to lead to deflationary pressure on service and material costs.

All that being said, it's important to point out that our 2019 budget does not assume any of these additional operational or deflationary savings I just mentioned. I would also like to mention that these standalone well costs include all pad and facilities costs and all flowback water costs, which our peers may not include in their reported well costs.

We remain focused on efficient capital spending in 2019, which will benefit from certain capital expenditures made during the fourth quarter of this last year of 2018. In particular, with better construction, weather conditions than we typically see in the latter part of the year, we invested $78 million for pads, roads and facilities in the fourth quarter, and we now have 18 pads that are in progress and planned to be turned to sales in 2019 and 2020. Additionally, as we discussed at our Analyst Day in early 2018, we transitioned to primarily building our pads today on larger footprints. Larger footprints allow us to be more capital efficient as we are able to operate under different scenarios such as drilling and completing pads concurrently or continuing to produce from wells on one side of a pad while drilling or completing wells on the other side of the pad. This ultimately results in a meaningful reduction in cycle times from spud to first sales and results in better alignment between capital spending and cash flow.

Looking ahead to 2019, as a result of the focused spending on pad infrastructure and equipment in 2018, we expect to be at the low end of our previously announced drilling and completion capital budget of $1.3 billion to $1.45 billion on a standalone basis and $1.1 billion to $1.25 billion on a consolidated basis.

Turning to Slide #8 titled Mariner East 2 Uplift. We're excited to have ME2 now in service. February represented the first month that we nominated our committed volume of 50,000 barrels a day of propane and butane at the Marcus Hook docks. Based on our contracts in place and current market pricing, we expect to receive a premium to Mont Belvieu pricing of at least $0.05 a gallon at the dock. As illustrated on this slide, this translates into an uplift of about $2 to $4 a barrel when compared to railing to the Mont Belvieu or Conway markets. It's also important to note that in addition to the $2 to $4 per barrel uplift on a netback basis, the price received for the volume shipped on ME2 will reflect the price at the dock, and the ME2 costs will be recorded as a transportation expense.

If you think about the 52% of WTI realized pricing in the fourth quarter for our C3+ NGLs, the shift in sales point related to ME2 volume alone would have resulted in about a 7% pickup in realized pricing relative to WTI. When you include the uplift, that adds another 2% to 4% on a percent of WTI basis or north of 60% WTI. We like the position we are now in as the largest NGL producer in the U.S. with significant exposure in the international market out of Marcus Hook.

In summary, we had a strong year in 2018, reducing our final -- financial leverage to 2.2x and we grew production nearly 900 million cubic feet equivalent per day over the last 12 months to over 3 Bcf equivalent a day, and also another accomplishment is that we announced the simplification of our midstream organization. Entering 2019, we now have a significant scale, product diversification and a strong balance sheet to manage through commodity price volatility. Our long-term strategy centers on prudent capital deployment, continued focus on full cycle rates of return and generating free cash flow, all while maintaining a strong balance sheet.

With that, I will turn it over to Glen for his comments.

Thank you, Paul. In my comments today, I will briefly touch on the expected change to our financial reporting following the simplification transaction, highlight our fourth quarter and full year financial results and discuss our 2018 reserves. I will also provide some additional thoughts around our 2019 guidance and moderated long-term outlook and finish with a discussion around how we are positioned to succeed in the years ahead.

Let's first talk about our plans to deconsolidate AM from AR from a financial reporting perspective. Upon closing of the midstream simplification transaction, 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 think this is a very good outcome for AR for a number of reasons. First, it will greatly improve 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 without having to dive into the complexities of the consolidated accounting rules. As an example, as of year-end 2018, Antero's consolidated net debt to adjusted EBITDAX was 2.7x, which is what shows up on financial data screening services such as Bloomberg or Factset. On a standalone E&P basis, which is a more appropriate measure, given AM's debt is nonrecourse to AR, Antero Resources standalone leverage was 2.2x or 0.5x lower than how it is viewed from a Street perspective. In our view, this transition will minimize future inconsistencies among analysts, investors and financial screening services on AR's leverage EBITDA capital and free cash flow, to name a few, and therefore significantly improve our transparency.

It is important to point out that AR will still own approximately 31% of new AM upon closing of the simplification transaction, assuming the cash and stocks mix is received by all parties and that we continue to believe in the benefits of integrated model and visibility and cooperation between our upstream and midstream businesses. With that said, we are excited these changes will occur from an accounting standpoint as we think it is another important step in helping to simplify the story.

Now moving on to the fourth quarter. During the quarter, net production averaged a record 3.213 Bcfe per day, delivering 37% year-over-year growth and 18% sequential growth, including a record 163,000 barrels a day of liquids. Liquids production increased 51% year-over-year and 25% sequentially, reflecting a continued emphasis on developing our liquids-rich acreage. Net liquids production included 12,200 barrels a day of oil, 103,000 barrels a day of C3+ NGLs and 47,000 barrels a day of ethane, all new records for Antero.

During the fourth quarter, Antero realized natural gas price was $3.83 per Mcf before hedges, representing a $0.19 per Mcf premium to the average NYMEX Henry Hub price. We expect to continue delivering pure leading natural gas realizations in 2019 as reflected in our guidance for natural gas realizations before hedges at a $0.15 to $0.20 per Mcf premium to Henry Hub. As we announced in December, during the fourth quarter, we did opt to monetize and restructure a portion of our natural gas portfolio for $357 million in net proceeds. This transaction allowed us to further delever while maintaining upside to the natural gas strip in 2019.

Our resulting hedge portfolio, as shown on Slide #9, 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.

Moving on to liquids pricing during the quarter. We realized an unhedged C3+ NGL price of $30.92 per barrel. As Paul previously highlighted, we expect our realized NGL prices to strengthen on a relative basis to Mont Belvieu with ME2 now in service. This is an important piece to our business in 2019 and beyond as every $5 per barrel increase in realized C3+ NGL prices results in an incremental $180 million in cash flow based on the midpoint of our 2019 C3+ NGL production guidance of 100,000 barrels per day.

Now let me touch a bit more on our long-term outlook and what that means relative to our firm transport portfolio. As outlined on Slide #10 titled Attractive Firm Transportation Portfolio, we are targeting a 10% to 15% production growth CAGR through 2023, so over the next 5 years beyond this year. As you can see on this slide, all of our committed firm transportation's now in service. This provides us with significant visibility into our expected pricing for the foreseeable future.

For 2019, we are forecasting a $0.15 to $0.20 premium to Nymex on our gas production and expect to realize premiums to Nymex for the next several years, as you can see in green on that chart. While we are not fully utilizing the pipelines today, we expect our net marketing expense to decline from a manageable peak in 2019 of approximately $0.20 per Mcfe to less than $0.05 per Mcfe by 2022, when we expect to fill our firm transport other than the low-cost regional FT we are committed to.

As you can see, our net marketing expense is essentially fully offset by the benefits that this portfolio provides by delivering our volumes into premium priced regions. These estimated net marketing expenses exclude the potential for third-party mitigation that Antero has taking advantage of in prior periods by marketing third-party gas and capturing the spread. Further, our hedge portfolio mark-to-market value of approximately $600 million, which was put in place at the same time as these FT commitments, more than offsets the $500 million of projected net marketing expense.

In summary, we expect to continue realizing premiums to NYMEX and declining net marketing expenses as we fill our commitments over the next several years, a great pathway to growth.

Shifting gears a bit, I would like to discuss some of the takeaways from our 2018 reserves as highlighted on Slide #11 titled Consistent Reserve Growth and Attractive Recycle Ratio. We increased 2018 proved reserves 4% from 2017, including a 27 -- including a 22% increase in proved reserves. The PV-10 of our proved reserves at SEC pricing was $12.6 billion, and the PV-10 of our proved developed reserves was $8.4 billion. As we look ahead to the development of our reserves, it is important to point out that the future cost associated with this development is expected to be approximately $0.48 per Mcfe on a standalone basis or $0.44 on a consolidated basis. When you compare this expected development cost with our fourth quarter actual results, we are generating a very attractive unhedged recycle ratio of 3.6x. Overall, we were pleased with the growth of our 2018 reserves and look forward to continue generating additional value based on our long-term outlook.

Before I conclude, I did want to mention that we recently added a natural gas fundamentals presentation to our website. Slide #12 provides the summary to this presentation. In short, we do not believe that the natural gas true-up appropriately reflects market fundamentals as strong demand combined with the sheer magnitude of the base decline are underappreciated by the market. Secondly, there are a number of technical factors that have depressed the long-term strip.

Further, in an effort to align spending with cash flow projections, both Appalachian and Permian producers are reducing 2019 capital budgets, which results in lower supply growth in 2019 with an even more meaningful supply impact in 2020. If you have not yet taken a look, we invite you to visit our website to review our macro thoughts on natural gas in more detail.

As we enter 2019 with significant scale, low leverage and well hedged, we are well positioned to navigate through changing commodity price environments. We look forward to closing the midstream simplification in early March, which will provide Antero Resources with a minimum of $300 million in cash. We expect to remain disciplined on our 2019 development plan throughout the year, targeting the lower end of the CapEx guidance range, a plan that represents a 20% reduction expected spending levels compared to 2018.

On the liquids front, we're excited about Mariner East 2 being placed in service, which allows us to move nearly half of our C3+ NGL production to the export market and realize stronger NGL netback pricing than what we had been receiving over the last several years. We are focused on executing over 2019 plan that we believe will deliver superior returns to shareholders over the long term while also investing within cash flow.

With that, I will now turn the call over to Paul for a few more comments.

Thank you, Glen. Before we turn it over to the operator for questions, we'd like to make a few comments regarding a recent piece of news regarding our recent $3.15 million settlement with the EPA and the Department of Justice regarding an environmental violation. We were a little disappointed that the Department of Justice press release did not clarify that the incidents occurred just short of 9 years ago in June of 2011. We do take our company reputation seriously and are extremely proud of our stellar operating track record.

I'd like to turn the call over to Al Schopp, our Chief Administrative Officer and Senior Vice President, West Virginia, to provide a little bit more detail. Al?

Thank you, Paul. This is Al Schopp. I would just concur with Paul in that we were a little disappointed in the characterization and the people who really did not take the time to understand the story. Back in, I would say, spring of 2011, we had hired third-party consultants to do our delineations, which is the prudent thing to do. Midstream had hired some and upstream had hired some, and it ended up at one of our sites that had a compressor pad being built and a well pad being built. And there was some disagreement about what the interpretation of ephemeral and intermittent streams and some wetlands would be back in that time. There was a lot going on in the industry at that time. You probably recollect seeing some others, XTO, Chesapeake and the like, had also gone through this characterization problem. We then -- the EPA did come out, and they clarified how they would like those to be interpreted and had cited about 9 of our sites for what they called fill into stream to wetland, which is basically dirt when you're building the construction pad or the compressor pad. And so at that time, we then took what the EPA wanted as interpretations, and we voluntarily went back through to 2009 to the very first pad that we had ever built, and we used to this more stringent set of criteria to reevaluate every site that Antero had ever built.

Now from June 30, 2011, when we met with the EPA and volunteered to go backwards, we changed our entire process, our entire delineation, consultant program to make sure that we had one consultant, EPA-approved consultants and that they certainly understood the requirements of the EPA for ephemeral intermittent streams and associated wetlands. And from that time forward, the only environmental issues we've really had in that extent have been with slips, which we have received hundreds of Army Corps of Engineers permits with all of our delineations and have had no problems since June 30, 2011.

So basically, the 2 items of that, that were put out there was a $3 million penalty and then they said associated reclamation cost of $8 million. We basically believed that the reclamation cost over the next 5 years will be closer to $3 million, $3 million to $4 million. Some of the sites, literally, the estimates are $7,000. They are just -- most of these, if not all of them, will be in our normal course of reclamation of the pads. These pads are now 10 years old. We have not been able to reclaim them in the ordinary course of business because of the ongoing negotiation with the Department of Justice. So we now will be able to do that over the next 3 years. The other part of the what they call their $8 million, which we did not give them that number, is we need to determine which -- what mitigation -- we're still looking for the estimate of what mitigation would be, but we do believe it would be under $5 million. And so certainly, we believe that this whole project will be done in under the $8 million that they talked about.

So those issues, unfortunately, had been mischaracterized, I would say, in a good part in the press. This is not frac waste. This is not frac dumping. This was literally dirt into a intermittent or ephemeral stream for the most part in spring of 2011, and we certainly are very proud of our environmental record here in West Virginia since that time of mid-2011.

Thank you, Al. And now we'll turn the call over to operator for questions.

(Operator Instructions) Our first question comes from Subash Chandra with Guggenheim Partners.

Maybe for Paul. The marketing expense, just curious, I assume you mitigate a good amount of that unused FT capacity caused by either sub-running capacity or purchasing gas. Just curious as you look into 2019, does anything change those dynamics such as converging basis dips in the basin or slower-growth objectives from third parties?

Yes. That's a good question, Subash. So in our a little further back past when there was pretty strong spreads, we were able to buy third-party gas, of as much as 0.5 Bcf a day and move it through our pipe and collect the spreads. And so we were offsetting a good many tens of million dollars of demand charges. At the moment, there is approximately 2.5 Bcf of available capacity really between the Mountaineer XPress pipe and Nexus, and so the basis differentials have narrowed. We do see as our -- we and our peers grow, that the pipe will begin to fill again, and so we do expect to see basis differentials and spreads improve. In the meantime, we are taking on certain third parties and moving gas around just to optimize our transportation. So right now, narrow spreads but the pipes will fill over the medium term.

And just to be clear, the numbers that we put out there, the net marketing numbers on a per Mcfe basis. Those include no mitigation whatsoever. So there's no assumption that we buy, sell gas or sublet capacities, Subash. So that's kind of the worst-case scenario, and I think we'll probably find some ways to mitigate that.

Okay, got it. No, I assumed it did. And I can go offline on this because when I sort of look at 10-K, you talk about $1 billion of annual FT charges. I think there might be some NGLs in there but -- and then I sort of divide by gross production in a year. It works out to about $1 or so. But the math could be off. So I thought that there was a fair number that was reflected in your guide. But if it isn't, that's, I guess, even more positive.

Yes. Subash, this is Mike. Your math is off so please give me a call, and I'll help you.

Yes, that's [off. It was getting] something a little over $200 million in gross dollars this year for the firm that we do not utilize, so it's as simple as that. It's very straightforward.

Got you. Okay, so that's the whole number. Got it. Okay. And then, Paul, you mentioned the larger pads and spud to sales improving. Could you sort of give us a frame of reference as to what it has been? What do you think this could do?

Yes. I think with the -- for the very largest pads, if you do the drilling one by one, completing one by one, the drill out of the plugs one by one, for a 10 or 12 well pad, you can really stretch things out 200 to 300 days before you put it online. And so with what we call concurrent operations and bigger pads, we can do all 3 things at once. So we can drill on one part of the pad and then move the rig over and drill another line of wells while we move the frac spread in. It's conceivable, although we haven't done it yet. At least, I can't think of an example where we have 2 frac spreads on the same pad, one working one line of wells, one working the other. We can also do drill-outs. We have done this where we have completion drill-outs where we're drilling out plugs on different lines of wells at the same time. How much can we shorten the cycle time? I think we can shorten, let's say, at the extreme if something calculated to 300 days before it can be 180 days now of cycle time. So on these big pads, which definitely deliver a tremendous amount of production, it does take time to do it so with larger pads. And I guess I would say also that definitely there's a correlation between more stages per day and the larger the pad just because there's so much logistics staging as we deliver sand to the mixers.

Our next question comes from Sean Sneeden with Guggenheim.

You guys highlight the benefit of Marcus Hook, and there was quite a bit of uplift there. Can you help us just kind of understand the marketing dynamics of some of that? Should we be thinking that a lot of those volumes are going to Europe? Sometimes the spreads between Europe and Asia kind of jump around. How should we kind of think about that over the long term?

Yes. So we're in our first year of marketing out of Marcus Hook and so got it divided up a couple of different ways, 2 different marketing companies that buy at the dock. And so roughly, I think you could say 1/3 is going to go to -- one of our product will go to Northwest Europe, another 1/3 will go to the far east and then the third portion will be LPG in the Atlantic Basin. So that goes to the East Coast to South America, West Coast of Africa. So we have it divided up. Certainly, there's freedom as the marketing companies take the ships off the dock or the ship loads off the dock that they can divert based on indices. But that's it. It's 1/3, 1/3, 1/3 conceptually. And -- but the marketing companies do the logistics and obviously go to the best netbacks.

Got it, that's helpful. And I guess, can you remind me how you guys think about the kind of -- and what kind of impact there is on sort of a longer-term guidance for your assumptions around kind of once you kind of get full-scale out of Marcus Hook what that means for in-basin realizations there?

Well, that's a good question, remains to be seen. It's just -- as we've said, our current net sales price within the sales pool, if we keep the liquids at home, we know one price that it has been historically. When we export out of the dock, there's a good uptick that equates to somewhere between $4 and $8 a barrel of NGL. So we know there's a price improvement. But we'll have to see empirically as we drain the basin, as we make the liquids more scarce, the liquids that get left behind, because it's roughly half of our liquids will go to Marcus Hook and half will stay within the basin and take advantage of tighter differentials. We'll just see, but we don't have a track record yet as to all the exporting out of Marcus Hook, what that will do to the net sales price within the basin. But should improve it, obviously.

Right, yes. And just remind us, you haven't actually assumed any benefit in some of your longer-term guidance. Is that how should we think about it for kind of what remains in-basin?

That's exactly right. So we've made assumptions on what gets exported, but we've not made any assumptions on an improvement on what gets left behind.

Yes, and just to follow up on that. I mean, we think the basin is producing about 400,000 barrels a day of C3+ NGL. So when you pull upwards of 100,000, maybe 145,000 barrels a day on the initial ME2 line out of the basin, that should have a positive impact. That will just improve over time as ME2 gets fully up and running. It gets to its full capacity and more stable to be drawing to the coast and -- or to the water and shipped.

Our next question comes from Holly Stewart with Scotia Howard & Weil.

Maybe, Glenn, just following up on that last ME2 comment. How much are you flowing today? And when do you expect to reach your full capacity on ME2?

Yes, I believe we are in the $40,000 -- 40,000 barrel a day plus today and probably approaching 50,000 barrels on some days. So we're close to our firm transport capacity on ME2 now.

And is there availability for you to do more?

Could be in short term, I think, it's possible depending on how quickly other shippers step up and use their capacity. And then as we talked about a number of times, I think -- we think by year-end anyway that the energy transfer at Sunoco will have this fully opened to 20-inch all the way. Then the capacity steps up from 145,000 barrels a day to 275,000 barrels a day, hopefully, by year-end this year, maybe sooner.

And with that, Holly, we'd have certain tranches that we can exercise or overflow rights. So we could move more should we decide to.

Great. That's a good color. Maybe just kind of looking at this Slide 4, you highlight a lot of company records versus where you ended up in 4Q. Just thinking about what's in the guidance, implied in the guidance right now and maybe loos like even on the completion stages per day, your record is almost twice what you did in 4Q. So can you just maybe talk through a few of those items and what's implied in the guidance currently and just kind of a bridging that gap for us?

Yes. Holly, thanks. In the guidance, we're assuming 5.5 stages a day, I believe, right?

5.2.

5.2. Excuse me, 5.25 a day in the guidance. So we feel good about being able to beat that. And I think if you can add another stage a day, that saves about $200,000 per well. So if we can get that 5.25 to 6.25 throughout the year, then that'd save another $200,000 per well.

Got it. That's a good color. And then maybe finally, just sort of a little higher level, Paul, on the last, I guess, few presentations. You've taken a bit of a more bullish stance on gas. Kind of curious, how you're balancing this versus the out-year hedge book?

Well, the out-year hedge book, we're certainly looking at beyond 2020. We still have some volumes hedged there. We, like so many others, watch pretty closely rig count in the different basins. We're watching production by the different basins. We're seeing -- we've seen things level off a little bit over the last few months. Is that just winter conditions? But as our natural gas piece that Glen and the finance department put out there, that there's big decline on the nation's reserve base and it has to be replaced, of course, and it also has to meet the new demand to go from the mid-80s to the low-90s Bcf a day and that's going to take drilling. And so many of the plays, about half of the plays will be dragged along by liquids, maybe it's scoop stack, Permian and NGL producers such as ourselves. But it's really the dry gas plays that are vulnerable and can they make up the other half of the difference in not only overcoming the decline but meeting the growth. So we're seeing it. We pride ourselves in understanding a lot of different plays and how much inventory might remain and the quality of what people are drilling, and usually quality declines as people drill up their inventory. So with that, we're watching production itself plus the buildup in each of the different basins, and we're feeling that there's a reason that prices will need to rise to encourage more drilling and more production. So with that, we're watching the possibility of hedging in the outer years but looking for just which way to do it and the opportunities that we see out there.

This concludes our question-and-answer session. I would now like to turn the conference back over to Mr. Michael Kennedy for any closing remarks.

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

The conference has now concluded. Thank you for attending today's presentation, and you may now disconnect.