Good day. Welcome to the Antero Resources first quarter 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 a touchscreen phone. To withdraw your question, please press star, then two. Please note this event is being recorded. I would like to turn the conference over to Michael Kennedy, Senior VP, Finance. Please go ahead, sir.
Thank you for joining us for Antero's first quarter 2018 investor conference call. We'll spend a few minutes going through the financial and operational highlights. Then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we've 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, 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 for the most comparable GAAP financial measures. Before I turn it over to Paul, I also quickly want to provide a brief update on the special committees that were assembled after soliciting feedback from our largest shareholders. As previously announced, we formed a special committee consisting of independent directors to evaluate the merits of potential measures to enhance Antero's valuation. In conjunction with this review, AM and AMGP have also established special committees. I would like to point out that the independent directors on the three special committees are not directors associated with private equity. All three special committees have hired financial and legal advisors and are working diligently to evaluate a range of potential measures.
There is no definitive timetable for completion of this evaluation. There can be no assurances that any initiatives will be announced or completed in the future. As I hope you can understand, because of the nature of this process, we will not be able to address any questions related to it or discuss it further during today's call. Joining me on the call today are Paul Rady, Chairman and CEO, and Glen Warren, President and CFO. I'll 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 am going to highlight our operational execution during the quarter, including the significant efficiencies and company records that we continue to achieve, and discuss how we can build on this momentum through further innovations. I will also provide an update on the 2018 completion schedule, including a few notable pads that we expect to place in surface in the second quarter. Glen will highlight several significant first quarter achievements, including our strong cash flow growth and continued reductions in our leverage metrics. First and foremost, we had an exceptional quarter on the operational front. Despite difficult operating conditions, processing outages, and severe weather, Antero delivered record production volumes.
The ability to deliver on our production targets was driven by our operational execution, as illustrated on Slide 3, titled "First Quarter 2018 Drilling and Completion Execution," as we have continued building momentum from 2017 with respect to drilling and completion efficiencies. Starting on the top left portion of the slide, in the Marcellus, we improved our average drilling days to 11.5 days from spud to TD, which represents a 4% reduction from 2017 average levels. Completion stages per day in the Marcellus averaged 4.3 stages per day for the full quarter, but increased to a company record of 5.1 stages per day in the month of March as the inclement winter weather had subsided.
This is particularly impressive given that we increased proppant loading per foot in the Marcellus by 23% to over 2,000 pounds a foot, and increased lateral lengths by some 8% as compared to year ago levels. Let's quantify what these efficiencies mean from a dollar per well standpoint. While our current budget assumes 4.5 completion stages per day, our ability to sustain higher stages per day during 2018 would not only provide incremental well cost savings relative to our current plan but would also bring forward production, resulting in less capital needed to achieve our production targets. An increase from 4.5 to 5.5 stages per day represents savings of approximately $90,000 per well. This is just one of many examples of why we are confident in our ability to mitigate any inflationary pressures with continued efficiency improvements.
In addition, during the quarter, Antero completed its longest laterals to date, with one well in the Marcellus at nearly 14,400 feet and four wells in the Utica at 17,400 feet each. As we continue to increase our laterals while making strides in drilling days and stages per day, we expect to achieve further efficiencies. Turning to slide four. We have also achieved multiple Marcellus drilling records recently. 7 of our top 15 lateral footage days have occurred this year, 2018. On slide number five, titled Operating Evolution Continues, our well cost pie chart shows that nearly 50% of our well costs are locked in through 2019 with our completion crews fully contracted and the majority of our rigs contracted through that time period.
Although our forecast assumes a 5% cost increase in consumables, primarily sand and gel, we expect to offset service cost inflation with continued efficiency improvements, and we remain on track to deliver the capital efficiencies outlined at our Analyst Day. Now let's shift to the pad level. The company is preparing to begin production on its two largest Marcellus pads to date by lateral footage. One is a 12-well pad that has a combined total lateral footage of 120,000 lateral feet, and the other pad is also a 12-well pad that has 106,000 lateral feet. We expect to place to sales the 24 wells on these two pads within this month, with expected production at a combined gross constrained rate of approximately 350-400 million cubic feet equivalent per day, including 20,000 barrels per day of liquids.
In the Utica, Antero turned to sales 10 wells in December 2017 on two adjacent pads that have produced over 24 Bcf of dry gas already, or 20 million cubic feet per day per well, and they remain at flat production after about 130 days online. These were the first wells completed by Antero in the Ohio Utica dry gas regime, and they were brought online in conjunction with the Rover Pipeline Phase 1B in service date, which was at the end of last year. We are very encouraged by the outperformance on this pad and the implications for dry gas Utica development in the coming years. Now, to briefly touch on our 2018 well completion plan. As discussed in the press release, we completed 21 wells over the first quarter, all on our liquids-rich acreage, many of which came online in late March.
During the second quarter, we plan to complete 44 wells, all of which will be completed on our liquids-rich acreage. This increase in sequential completion activity with a focus on liquids keeps us on track to achieve our full year production guidance of 2.7 BcfE per day in total, including 130,000 barrels a day of liquids. With that, I will turn it over to Glen for his comments.
Good morning. Thanks, Paul. Let me begin with some of the key financial achievements from the quarter. Despite severe winter weather that hit the Northeast in early January, which forced us to shut in a portion of our production temporarily due to processing plant outages, a downstream pipeline outage production averaged a record 2.38 BcfE per day for the quarter, an 11% year-over-year increase, including approximately 103,000 barrels a day of liquids. Liquids production included 5,900 barrels a day of oil, 63,300 barrels a day of C3+ NGLs, and 33,700 barrels a day of ethane. A sequential decline in liquids volumes in the quarter was related to processing downtime. While we expect a sequential increase in liquids production in the second quarter. Moving on to realized pricing during the first quarter.
We realized $3.14 per Mcf before hedges on our natural gas production during the quarter, a $0.14 per Mcf premium to the average NYMEX Henry Hub price. The first quarter performance once again illustrated the strategic advantage of a diverse firm transportation portfolio that allows us the optionality to move virtually all of our gas to premium markets. Turning to slide number six, titled Appalachian Peer Pre-hedge Natural Gas Realizations, you can see that we have been a peer leader in natural gas price realizations for the past five years. Additionally, the first quarter represented the 15th consecutive quarter in which Antero Resources's all-in natural gas price realizations exceeded NYMEX Henry Hub prices. For reference, since Antero Resources's IPO in 2013, Antero Resources has realized natural gas prices including hedges above $3.50 per Mcf in all 19 quarters, excluding the impact of WGL breach in the third quarter of 2017.
Given our attractive hedge book, which includes being 100% hedged at $3.50 per Mcf in both 2018 and 2019, combined with our large FT portfolio, we expect to continue delivering superior price realizations going forward. Our approach of managing with a long-term focus, which inevitably includes oil and gas price troughs and transportation bottlenecks, has served us well, as you can see from our consistency in generating attractive margins. As a reminder, we did not have any material pricing impacts this quarter from contractual disputes that we discussed during our last earnings call, and do not expect any material impacts to our realizations from these disputes going forward, as we've largely mitigated the volume exposure. Due to better than anticipated pricing, we now expect natural gas price realizations at the high end of our prior guidance of a premium to NYMEX of $0.00-$0.05 per Mcf.
Moving on to liquids pricing for the quarter. We realized an unhedged C3+ NGL price of $36.38 per barrel, or 58% of NYMEX WTI. While NGL prices did not keep up with the rise in WTI prices during the quarter, on an absolute basis, NGL prices remained consistent with expectations and represented a 23% increase from a year ago. For the remainder of 2018, we are trending toward the low end of our guidance range of 62.5%-67.5% of WTI. However, as shown on slide number seven, propane fundamentals remain strong, with days of supply at the lowest level in five years and inventory 24% below the five-year average. As you can see, the Mont Belvieu C3 or propane price is $0.82 a gallon for the remainder of the year, approaching $0.83 this morning.
When combined with the additional liquids transport capacity coming during the second half of 2018 at Mariner East 2, we are confident in the continuation of attractive liquids pricing. Importantly, while trending toward the low end of our guidance relative to WTI oil, absolute C3+ pricing is relatively unchanged from year-end 2017 and continues to be attractive relative to the year ago level, as illustrated on slide number eight, titled C3+ NGLs Price Improvement. Moving forward, we believe that our firm transportation and hedge book will continue to be significant competitive advantages for Antero Resources as the uncertainty around both Henry Hub gas pricing and Northeast bases is likely to continue.
As a reminder, as shown on slide number nine, for 2018 and 2019, assuming the midpoint of production targets, we are 100% hedged at an average price of $3.50 per MMBtu in both years, representing a premium of $0.70 per MMBtu or just over 25% above current strip pricing. I want to touch on the substantial marketing gain we reported this quarter. As highlighted on slide number 10, titled A Paired Trade Hedges Support Firm Commitments. As previously stated during the last earnings release, we had expected a net marketing gain for the first quarter. During periods of severe cold weather in January, we were able to resell purchased gas on the East Coast at a large premium. During the first quarter, this resulted in a net marketing gain of $59 million, or $0.27 per Mcfe.
Due to the January gas marketing gains, we previously reduced our net marketing expense guidance for the full year to $0.10-$0.125 per Mcfe from $0.10-$0.15 per Mcfe previously. To briefly touch on some financial highlights from the quarter, we generated standalone adjusted EBITDAX of $488 million, including the marketing gain, a 31% increase sequentially, and a 52% increase over the year-ago period. Standalone adjusted operating cash flow was $433 million, 66% higher than the year-ago period. Slide number 11 highlights our historical leadership when comparing standalone EBITDAX margin over the last five years to our Appalachian peer group. Back to our integrated long-term strategy. Antero continues to deliver peer-leading margins year after year due to our strong hedge book, large firm transportation portfolio to premium markets, and increasing exposure to liquids prices. We expect this trend to continue.
In summary, we have reached an important inflection point for our company, and our first quarter results showcase the significant momentum we have toward executing on our long-term plan outlined at this year's Analyst Day in January. Management remains dedicated to execution and delivering on this long-term plan. We continue to focus on our capital-efficient Marcellus liquids-rich inventory and a declining leverage profile, which, as you can see on slide number 12, is at the lowest level in our history at 2.5 times on a standalone basis. Leverage is projected to decline further towards 2.0 times at the end of this year. As shown in slide number 13, titled Antero Profile to Drive Multiple Expansion, this momentum will place Antero in an elite group of just seven E&P companies that have scale, double-digit production growth, low leverage, and generate free cash flow.
All of whom trade at premium multiple valuations relative to Antero. With that, I will now turn the call over to the operator for questions.
We will now begin the question and answer session. To ask a question, you may press star, then one on your touch-tone phone. If you're 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 then two. The first question is from Subash Chandra of Guggenheim. Please go ahead.
Hi, Paul. Good morning. The dry gas commentary in the Utica, is there a possibility that it plays a bigger role in the program? I think it was maybe a quarter of the drilling program, 20% of the drilling program this year. Are you thinking of weighting that a bit more based on the results you've seen? If so, does it add to the program, or does it displace some of your program?
Good question. We're pleased with the results there in the Utica. We're not expanding our CapEx program. We're still at the same spot. In fact, probably Utica is going to be 15%-20%. Even though these are outstanding wells, the economics on our Marcellus liquids wells are even stronger. Really, no divergence from the path like the Utica, but it still plays a smaller role. We're not looking to expand the CapEx, but to keep it the same and keep our focus mostly on Marcellus liquids.
Okay. Now, one of your peers in Appalachia, they're contemplating a carve-out of formations that have low NPV in their inventory. Is that something that you might be open to? Let's say even this Utica play, which I think with Rover has got some more attention, has been fairly flat. A play like that might be worth more to someone else. Any of those notions?
Yeah, we do have those notions from time to time, Subash. Right now, we're still pretty focused. We're aware that we could perhaps do that, but we do like that Utica and don't like to effectively farm it out in a drill co or whatever. We do have plans for the Utica, and that is good precious inventory, so not looking to let go of it. You're right, there could be some moving forward of PV, but what would be gained by moving forward might be lost by sharing it with somebody else.
Got you. Okay. The long laterals, everyone's sort of making that case, and you guys know drilling inside and out. One of the perspectives we've heard on long laterals is that there is a loss of efficiency. Maybe it's compensated by lower marginal cost. How do you feel about preserving the Bcf per 1,000 as you push these things beyond 3 miles or so? From toe, heel contributions, et cetera?
Yeah, it's a good question. We feel that we get equal production from the toe as from the heel and everywhere in between. As we drilled longer laterals, of course, we're watching it, and we plot it up in EUR per thousand as we go out the curve. If anything, our longer laterals, now they are in excellent areas, but they're above our type curves. We're really not seeing any loss going out longer so far. This is particularly true in the Marcellus, where we've gone out. Our longest completions are in the 14,200 range. In terms of frack efficiency for us, as we frack the toe, we're able to break that down. We have plenty of horsepower on the surface to break it down and pump away. There's plenty of pressure there.
Don't see anywhere near the friction loss, so we can break down those distance stages. Really still feel good about 14,000+. On our drilling schedule for this year and next, we are getting longer. We're going out to 15,000, 16,000, even 17,000 in the Marcellus in some places. Feel good about it. We really think that the efficiencies are there, and we're not going to see a loss as is reported in some of the other plays.
Got it. A final one for me. Appreciate your patience. In terms of NGLs, the summer months, should we anticipate an increase in the proportion of C3 pluses as a % of total NGL sales?
Let's see. I don't think so, Subash. I think it'll be a fairly consistent increase here over the year between C2 and C3 plus.
Okay. Got it. Thank you very much.
Thank you. Thanks, Subash.
The next question is from Welles Fitzpatrick of Johnson Rice. Please go ahead.
Hey, guys. Actually, it's Wells from SunTrust. On those NGL realizations, thanks for the great macro overview. As far as the in-basin pricing is concerned, can you talk to the Mariner East outage in March? I mean, did that affect the C3, C4 pricing? When that reverses, should we look to that to improve as we move into 2Q?
There was some minor effect, I'd say, on C3 plus pricing in March from that. It's still not back on, as you know, Mariner 1, which brought some more barrels to the region. We do anticipate that coming back on here in the next couple of weeks, hopefully, as we understand they're very close and just waiting on the regulatory bodies to sign off on the repairs. As far as ME2, we're still assuming that comes online here mid-year, and that's what Energy Transfer is still stating publicly, and that's what we're hearing from them. We're hopeful. We're assuming at least by July that we'll have ME2 online, and that's going to help a lot during the summer months. If it is delayed to later in the year, that certainly has some cost to it.
We'd estimate if it was delayed till year-end, it may cost us $30 million or so of sort of cash flow in the second half of the year. We don't anticipate that. We feel pretty good about the progress they're making. You've seen the numbers, probably they have 98% of the pipe in the ground, and I think they've completed something over 90% of the bores. They are making progress there. The second quarter's always a bit soft regionally, certainly, since you have to move so much product in the second and third quarter out of the region by rail without the pipe. We're really looking forward to the pipes getting in place.
Okay, perfect. Just one follow-up, it's kind of goes to Subash's question. Obviously, you have the 17,000 plus footer per slide 21. There are diminishing returns. I mean, is that 17,000 footer, is that something that was done because of lease geometry? I mean, do you think you would work that type of lateral into the overall program on a wider basis?
Yes, absolutely. Are you talking about the Utica 17,000 footers?
Yeah, that's right.
Yeah. We've completed four of those, and they'll be brought online shortly. No, we feel really good, as Paul had mentioned, about going out further. In the gas plays and even the gas and liquids plays, we just don't see that decline in productivity as you go out further. You're incentivized as a producer to drill longer as long as you can manage the cycle times on the pad. That goes back to our Analyst Day when we sort of rolled out our research and look into concurrent operations where we actually spread out the wellheads on a larger pad, and we're able to drill and complete on that same pad concurrently. That's where we're headed over the longer term, and I think we'll be actually executing on some of those later this year.
That really improves your cycle time in terms of getting to first production and facilitates drilling those long laterals in that 14 to 17,000 foot range and capitalizing on the efficiencies that you get from going out that far, not losing any efficiency on your EUR per thousand.
Wonderful. That's all I have. Thanks for taking my questions.
Thank you. Thanks, Wells.
The next question is from Brian Singer of Goldman Sachs. Please go ahead.
Thank you. Good morning.
Good morning, Brian.
Hi, Brian.
Certainly noteworthy that well costs still are maybe falling here with some of the efficiencies. How do you think about the trade-off of meeting production expectations and potentially spending less capital versus sticking with the CapEx budget and producing more? If you're drilling wells more swiftly, would you need to choose at some point here whether to drop rigs versus end up drilling more wells than expected?
Well, that's true at some point, Brian. Right now, we're just looking to manage to the budget for this year. I think there will be some inflation out there. We analyzed it and shown that we expect to see sort of 2% inflation this year, and our well cost somewhat offset by efficiencies. I think if we are able to capture even more efficiency than that, which we fully anticipate doing, then we may have some room there. I don't think you'll see us increasing the capital budget in order to grow production. I think we'll stick to our production targets and lean more towards capitalizing on the additional free cash flow that you get from spending less.
Great, thanks. Second question's a little off the beaten path. Antero's always been aggressive in looking to reduce longer-term pricing risk with the hedges going out into the 2020s. I guess, A, do you see less of a need to continue to do that as the cash flow ramps up and potentially the balance sheet improves? Are there opportunities beyond hedging, potentially in the global gas market, which has tightened? Are there opportunities to sign contracts to provide stable prices at levels greater than what we would see in the forward curve?
Yeah. As we grow, one could make the case for not as much need to hedge. We have about a two-year, two and a half year glide path here where we're quite fully hedged. We have time to watch and hope that higher gas prices come back in on the outer part of the curve, and we can play the contango. We watch it all the time, but we're patient, and we'll just see where that goes. I will say, as our volumes get higher and higher, I don't know if we'll seek to hedge it all or just some portion of it. As to what's out there on the physical side, we are already a provider of LNG to Cove Point and to Sabine, and we'll also be a provider at Freeport.
Our totals are approaching $600 million a day on those projects, and maybe even another 100 or two here and there. On global gas, it's a good solid physical market. They are typically NYMEX based, and one can hedge the NYMEX and do whatever one wants there, whether it's trying enhancing that price. We do look to at least do those pretty straightforward approaches. If there's something else out there, as in global LNG, FOB, the ship, we look into that. Don't know if that's realistic to make it through the LNG facility and get the higher price or not, but we would at least consider it.
Thank you very much.
The last question is from Bob Morris of Citi. Please go ahead.
Thank you. Paul, Glen, you sort of fleshed out how you managed the budget with the excess cash flow and capital gain you had this quarter with a nice improvement in efficiency, that those continue going forward. The second question I had was just on the sand cost. You said you assumed about 5% inflation on consumables, but what are you seeing on the sand side, given that more local sand is being consumed locally in other basins? Is that taking some pressure off of sand costs in the Marcellus and Utica? Are there any issues with the availability of transportation to move that sand into your regions of operation, or how is that playing out?
I think it's playing out favorably for the producer, the whole trend towards regional sand. I laugh that early on, say six months ago, I was a sand snob and said, "Northern White only. We don't want to take that risk." We're looking just like others. We've already done some pilots with regional sands that are cheaper, 100 mesh pilots, regional sand, and so far so good, I would say. The whole trend within the industry to seek out regional is going to put less pressure, obviously, on the Northern White. We are open-minded on that, and if one expands the supply to include all the regionals, then that's going to help lower prices. I do think on the transportation side, a lot of people, including ourselves and some of our service companies, are working on that.
Low unemployment is great, we and the service companies are seeing it in trucks and trains that some of that is jamming up. There are some that are going to their own trucking companies just to make sure they can move the product, and more focus on transload and so on. I do think that is a focus of the industry right now. We found what could be a huge new supply taking into account regionals, now it's focused on the logistics of it. We do see that it's favorable, and our bias is that both the sand itself and the supply chain are going to help us. We'll at least be able to stay flat.
Okay. That's great. Thank you.
This concludes our question and answer session. I would like to turn the conference back over to Michael Kennedy for any closing remarks.
Thank you for joining us on our call today. If you have any further questions, please feel free to contact us. Thanks again.
The conference call has now concluded. Thank you for attending today's presentation. You may now disconnect.