Good day, and welcome to the Antero Resources fourth quarter and year-end 2018 earnings conference call and webcast. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw your question, please press star then two. 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 four, 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 one 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, 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 five 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 two and a half times more than the closest competitor by our analysis. This extensive liquids inventory is a clear competitive advantage. Let's turn to our 2019 development plan and long-term outlook, which we announced on January 8th. We are expecting annual production growth during 2019 in the range of 16%-20% while spending within cash flow.
Slide six, titled Disciplined Long-Term Development Plan, highlights our production growth through 2023 under multiple commodity price scenarios, ranging from $50-$65 per barrel WTI, and $2.85-$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, 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 de-levering. To provide some more details on capital and our well costs, I'll point you to slide seven, entitled 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 costs 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 Antero Clearwater Facility. We expect the D&C capital cost reductions by multiple public operators to date to lead to deflationary pressure on service and material costs.
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 plan to be turned to sales in 2019 and 2020.
As we discussed at our Analyst Day in early 2018, we've transitioned to primarily building our pads today on larger footprints. The 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 D&C capital budget of $1.3 billion-$1.45 billion on a standalone basis and $1.1 billion-$1.25 billion on a consolidated basis. Turning to slide number eight, 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-$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-$4 per barrel uplift on a net back 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. 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%-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 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. Another accomplishment is that we announced the simplification of our midstream organization. Entering 2019, we now have 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 non-recourse 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 stock mix is received by all parties, and that we continue to believe in the benefits of the 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. 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 peer-leading natural gas realizations in 2019, as reflected in our guidance for natural gas realizations before hedges at a $0.15-$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 de-lever while maintaining upside to the natural gas strip in 2019.
Our resulting hedge portfolio, as shown in slide number nine, protects 100% of 2019 and 55%-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 number 10, titled Attractive Firm Transportation Portfolio, we are targeting a 10%-15% production growth CAGR through 2023, so over the next five years beyond this year. As you can see on this slide, all of our committed firm transportation is 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-$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 taken 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 number 11, titled Consistent Reserve Growth and Attractive Recycle Ratio, we increased 2018 proved reserves 4% from 2017, 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 costs 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 3.6 times. 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 number 12 provides the summary to this presentation. In short, we do not believe that the natural gas strip 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.
In an effort to align spending with cash flow projections, both Appalachian and Permian producers are reducing 2019 capital budgets, which will result in lower supply growth in 2019 with an even more meaningful supply impact in 2020. If you've 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 in expected spending levels compared to 2018.
On the liquids front, we are 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 net back pricing than what we had been receiving over the last several years. We are focused on executing on the 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, Glenn. 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 nine 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 on 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. 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.
The EPA did come out, they clarified how they would like those to be interpreted, and had cited about nine of our sites, for what they called fill into streams or wetland, which is basically dirt when you're building a construction pad, or the compressor pad. At that time, we then took what the EPA wanted as interpretations, we voluntarily went back through to 2009 to the very first pad that we'd ever built, and we used this more stringent set of criteria to reevaluate every site that Antero had ever built. From June 30th, 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.
From that time forward, the only environmental issues we've really had in that extent have been with slips. We have received hundreds of Army Corps of Engineers permits with all of our delineations and have had no problems since June 30, 2011. Basically, the two 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 believe that the reclamation cost over the next five years will be closer to three to four. Some of the sites, literally, the estimates are $7,000. 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.
We now will be able to do that over the next three years. The other part of what they called their $8 million, which we did not give them that number, is we need to determine what mitigation. We are still looking for the estimate of what that mitigation would be, but we do believe it would be under $5 million. Certainly, we believe that this whole project will be done in under the $8 million that they talked about. Those issues, unfortunately, have been mischaracterized, I would say, in a good part in the press. This is not frack waste. This is not frack dumping. This was literally dirt into an intermittent or ephemeral stream, for the most part, in spring of 2011. We have certainly are very proud of our environmental record here in West Virginia since that time of mid-2011.
Thank you, Al Schopf. Now, we will turn the call over to operator for questions.
We will now begin the question and answer session. To ask a question, you may press star 1 on your touch tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star 2. Our first question comes from Subash Chandra with Guggenheim Partners. Please go ahead.
Yeah. Hi, good morning. Maybe for Paul. Hi. The marketing expense, just curious, I assume you mitigate a good amount of that unused FT capacity cost by either subletting 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?
Yeah, that's a good question, Subash. A little further back past when there was pretty strong spreads, we were able to buy third-party gas of as much as half a BCF a day and move it through our pipe and collect the spreads. We were offsetting a good many tens of million dollars of demand charges. At the moment, there's approximately two and a half BCF of available capacity, really between the Mountaineer XPress pipe and Nexus. The basis differentials have narrowed. We do see as we and our peers grow, that the pipe will begin to fill again. 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.
Right now, narrow spreads, the pipes will fill over the medium term.
Just to be clear, the numbers that we put out there, the net marketing numbers on a per basis, those include no mitigation whatsoever. There's no assumption that we buy, sell gas, or sublet capacity, Subash. 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. I can go offline on this because when I sort of look at the 10-K, you talk about $1 billion of annual FT charges. I think there might be some NGLs in there. Then I sort of divide by gross production in a year, works out to about $1 or so, but the math could be off. I thought that there was a fair number that was reflected in your guide. If it isn't, that's I guess even more positive, so.
Yeah. Subash, this is Mike. Your math is off, so please give me a call and I'll help you.
Okay, will do.
Yeah, that math is off. It's going to be something a little over $200 million in gross dollars.
Right.
Firm that we do not utilize. It's as simple as that. It's very straightforward.
Gotcha. Okay. That's the whole number. Got it. Okay. 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?
Yeah, I think, 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. With what we call concurrent operations and bigger pads, we can do all three things at once. 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 frack spread in. It's conceivable, although we haven't done it yet, at least I can't think of an example where we have two frack 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. On these big pads, which definitely deliver a tremendous amount of production, it does take time to do it. 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.
Okay. Thanks a lot, guys.
Thanks, Subash.
Our next question comes from Sean Sneeden with Guggenheim. Please go ahead.
Hi. Good morning.
Hi, Sean.
Thanks for taking the questions.
Sure.
You guys highlight the benefit of Marcus Hook, and there's 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 think about that over the long term?
Yeah. We're in our first year of marketing out of Marcus Hook, got it divided up a couple of different ways. Two different marketing companies that buy at the dock, roughly, I think you could say one third of our product will go to Northwest Europe, another third will go to the Far East, and then the third portion will be LPG in the Atlantic Basin. That goes to the East Coast of South America, West Coast of Africa. We have it divided up. Certainly, there's freedom as the marketing companies take the ships off the dock or the shiploads off the dock that they can divert based on indices. That's it, is third, third conceptually. The marketing companies do the logistics and obviously go to the best net backs.
Got it. That's helpful. I guess, can you remind me how you guys think about and what kind of impact there is on some of the longer-term guidance for your assumptions around once you 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. 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. We know there's a price improvement, we'll have to see empirically as we drain the basin, as we make the liquids more scarce, the liquids that get left behind. 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, we don't have a track record yet as to all the exporting out of Marcus Hook, what that'll do to the net sales price within the basin.
Should improve it, obviously.
Right. Yeah. Just remind us, you haven't necessarily assumed any benefit in some of your longer-term guidance. Is that how we should think about it for what remains in basin?
That's exactly right. We've made assumptions on what gets exported, we've not made any assumptions on an improvement on what gets left behind.
Got it. That's very helpful. Thanks for all the time, guys.
Yeah, just to follow up on that, we think the basin is producing about 400,000 barrels a day of C3+ NGLs. 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, and that will just improve over time as ME2 gets fully up and running and gets to its full capacity and more is able to be drawn to the coast or to the water and shipped.
Our next question comes from Holly Stewart with Scotia Howard Weil. Please go ahead.
Good morning, gentlemen. Maybe Glen, 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?
Yeah, I believe we're in the 40,000 barrel a day plus today, and probably approaching 50,000 barrels on Sunday. We're close to our firm transport capacity on ME2 now.
Is there availability for you to do more?
Could be in the short term, I think. It's possible, depending on how quickly other shippers step up and use their capacity. As we've talked about a number of times, I think we think by year-end anyway, that Energy Transfer and Sunoco will have this fully open the 20-inch all the way. The capacity steps up from 145,000 barrels a day to 275,000 barrels a day, hopefully by year-end this year, maybe sooner.
Great.
With that, Holly, we'd have certain tranches that we can exercise or overflow rights. We could move more, should we decide to.
Great. That's good color. Maybe just looking at this slide four, 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 looks like even on the completion stages per day, your record is almost twice what you did in 4Q. Can you just maybe talk through a few of those items, and what's implied in the guidance currently, and just kind of bridging that gap for us?
Yeah, 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.
We feel good about being able to beat that. I think if you can add another stage 1 a day, that saves about $200,000 per well. If we could get that five and a quarter to six and a quarter throughout the year, that'd save another $200,000 per well.
Got it. That's a good color. Then maybe finally, just sort of a little higher level, Paul, on the last, I guess, few presentations are taking a bit of a more bullish stance on gas. I'm kind of curious how you're balancing this versus the out-year hedge book.
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've seen things level off a little bit over the last few months. Is that just winter conditions? As our natural gas piece that Glen and the finance department put out there, that there's a big decline on the nation's reserve base, and it has to be replaced, of course. 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. 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.
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. 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. Usually quality declines as people drill up their inventory. 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. 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.
Great. That's helpful. Thanks, guys.
Holly.
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.