Good day, and welcome to the Antero Research's First Quarter 2018 Earnings Conference Call and Webcast. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. 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 Q1 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 and A. I would also like 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 3 special committees are not directors associated with private equity. All 3 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, and there can be no assurances 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 Glenn Warren, President and CFO. I'll now turn the call over to Paul.
Thank you, Mike, and thank you to everyone for 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 service in the next in the second quarter. Glenn will then highlight several significant first quarter achievements, including our strong cash flow growth and continued reductions in our leverage metrics. 1st 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 1st 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 a foot and increased lateral lengths by some 8% as compared to year ago levels. Now 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 In addition, during the quarter, Antero completed its longest laterals to date with one well in the Marcellus at nearly 14,400 feet and 4 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 4.
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 5 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 2 largest Marcellus pads to date by lateral footage. 1 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 the sales the 24 wells on these 2 pads within this month with expected production at a combined gross constrained rate of approximately 350,000,000 to 400,000,000 cubic feet per day, including 20,000 barrels per day of liquids. In the Utica, Antero turned to sales 10 wells in December 2017 on 2 adjacent pads that have produced over 24 Bcf of dry gas already or 20,000,000 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 on line 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 Q1, all on our liquids rich acreage, many of which came online in late March. During the Q2, 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 Bcf equivalent per day in total, including 130,000 barrels a day of liquids.
With that, I will turn it over to Glenn 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 plus 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 Q1.
We'd 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 Q1 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 6, titled Appalachian Peer Prehedge Natural Gas Realizations, you can see that we have been a peer leader in natural gas price realizations for the past 5 years. Additionally, the Q1 represented the 15th consecutive quarter in which AR's all in natural gas price realizations exceeded NYMEX Henry Hub prices. For reference, since AR's IPO in 2013, AR has realized natural gas prices, including hedges, above $3.50 per Mcf in all 19 quarters, excluding the impact of the WGL breach in the Q3 of 2017.
Given our attractive hedge book, which includes being 100 percent hedged at $3.50 per Mcf in both 2018 2019, combined with our large Feet 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 $0.05 per Mcf. Moving on to liquids pricing for the quarter.
We realized an unhedged C3 plus NGL price of $36.38 per barrel or 58 percent 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% to 67.5% of WTI. However, as shown on Slide number 7, propane fundamentals remain strong with days of supply at the lowest level in 5 years and inventory 24% below the 5 year average. And as you can see, the Mount Bellevue 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 twenty eighteen at Mariner East 2, we are confident in the continuation of attractive liquids pricing. Importantly, while turning toward the low end of our guidance relative to WTI oil, absolute C3 plus pricing is relatively unchanged from year end 2017 and continues to be attractive relative to this year ago level, as illustrated on Slide number 8 titled C3 Plus NGLs Price Improvement. Moving forward, we believe that our firm transportation and hedge book will continue to be significant competitive advantages for Antero as the uncertainty around both Henry Hub gas pricing in Northeast basins is likely to continue. As a reminder, as shown on Slide number 9, for 2018 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. Next, I want to touch on the substantial marketing gain we reported this quarter.
As highlighted on Slide 10, titled Appeared Trade Hedges Support Firm Commitments. As previously stated during the last earnings release, we had expected a net marketing gain for the Q1. 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 Q1, this resulted in a net marking gain of $59,000,000 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 to $0.125 per Mcfe from $0.10 to $0.15 per Mcfe previously.
Now to briefly touch on some financial highlights from the quarter, we generated standalone adjusted EBITDAX of $488,000,000 including the marketing gain, a 31% increase sequentially and a 52% increase over the year ago period. Standalone adjusted operating cash flow was $433,000,000 66 percent higher than the year ago period. Slide number 11 highlights our historical leadership when comparing stand alone EBITDAX margin over the last 5 years to our Appalachia 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 Q1 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 2.0x at the end of this year. As shown on Slide number 13 titled Antero Profile to drive multiple expansion, this momentum will place Antero in an elite group of just 7 E and 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. The first question is from Subash Chandra of Guggenheim. Please go ahead.
Yes. Hi, Paul. Your dry gas commentary yes, 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 quarter of the drilling program, 20 percent of the drilling program this year.
But are you thinking of weighting that a bit more based on the results you've seen? And if so, does it add to the program or does it displace some of your program?
Yes. Good question. We're pleased with the results there in the Utica, but it's still and we're staying we're not expanding our CapEx program. We're still at the same spot. And in fact, probably Utica is going to be 15% to 20%.
So even though these are outstanding wells, the economics on our Marcellus liquids wells are even stronger. So really no divergence from the path like the Utica, but it still plays a smaller role. And we're not looking to expand the CapEx, but just to keep it the same and keep our focus mostly on Marcellus liquids.
Okay. 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 and or let's say even this Utica play, which I think was 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?
Yes, we do have those notions from time to time Subash. But 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 DrillCo or whatever. So 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. And 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 along laterals is that there is a loss of efficiency, maybe it's compensated by lower marginal cost.
But how do you feel about preserving the BCF for 1,000 as you push these things beyond 3 miles or so and from toe, heel contributions, etcetera?
Yes, 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've drilled longer laterals. Of course, we're watching it and we plotted up in EUR per 1,000 as we go out the curve. And if anything, our longer laterals now they are in excellent areas, but they're above our type curves. So we're really not seeing any loss going out longer so far. And this is particularly true in the Marcellus, where we've gone out.
Our longest completions are in the 14,200 range. In terms of frac efficiency for us, as we frac the tow, we're able to break that down. We have plenty of horsepower on the surface to break it down and pump away. There is plenty of pressure there. I don't see anywhere near the friction loss, so we can break down those distant stages.
So really still feel good about 14,000 plus and on our drilling schedule for this year and next, we are getting longer. We're going out to 15,000, 16, even 17,000 in the Marcellus in some places and feel good about it. We really think that the efficiencies are there and we're not going to see a loss like as is reported in some of the other place.
Okay. And a final one for me. Appreciate your patience. The in terms of NGLs, the summer months, do you should we anticipate an increase in the proportion of C3 pluses as a percent of total NGL sales?
Let's see. I don't think so, Subash. I think it will be a fairly consistent increase year over the year between C2 and C3 plus
The next question is from Wes Fitzpatrick of Johnson Rice. Please go ahead.
Hey guys, actually it's Welles from SunTrust. But on those NGL realizations, thanks for the great macro overview, but 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? And when that reverses, should we look to that to improve as we move into 2Q?
There were 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. But we do anticipate that coming back on here in the next couple of weeks, hopefully, as we understand that very close and just waiting on the regulatory bodies sign off on the repairs. And 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.
So 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 $30,000,000 or so of sort of cash flow in the second half of the year. But 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. So they are making progress there. But the 2nd quarter is 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 pipes. So we're really looking forward to the pipes getting in place.
Okay, perfect. And then just one follow-up and 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?
Or is that something that 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 that we have? Yes, that's right. Yes, yes. So we've completed 4 of those and they'll be brought online shortly.
But now we feel really good, as Paul had mentioned, about going out further. In the gas plays and even the gas liquids plays, we just don't see that decline in productivity as you go out further. So you're incentivized as a producer to drill longer as long as you can manage the cycle times on the pad. And 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. So that's kind of where we're headed over the longer term and I think we'll be actually executing on some of those later this year.
And that really improves your cycle time in terms of getting to first production and facilitates drilling those long laterals in that 14,000 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 1,000.
Wonderful. That's all I had. Thanks for taking my questions.
Thank you. Thanks, Welles.
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 may be 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? And 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. But right now, we're just looking to manage through the budget for this year. I think there will be some inflation out there. We've kind of analyzed it and shown that we expect to see sort of 2% as TWO kind of inflation this year and our well costs somewhat offset by efficiencies. So 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.
And 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. And second question is a little off the beaten path. Ontario has 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?
Yes. So as we grow, yes, one could make the case for not as much need to hedge. We have about a 2 year, 2.5 year glide path here where we're quite fully hedged. And so 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. So we watch it all the time, but we're patient and we'll just see where that goes.
And I will say as our volumes get higher and higher, I don't know if we'll seek to hedge at all or just some portion of it. As to what's out there on the physical side, we certainly we are already a provider of LNG to Cove Point and to Sabine and we'll also be a provider at Freeport. And so our totals are approaching $600,000,000 a day on those projects and maybe even another 100 or 2 here and there. So on global gas, it's a good solid physical market. They are typically NYMEX based and so one can hedge the NYMEX and do whatever one wants there, whether it's trying to enhancing that price.
So 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, Glenn, you sort of flushed out how you manage the budget with the excess cash flow and capital gain you had this quarter with a nice improvement in efficiencies. It does continue going forward. So 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? And are there any issues with the availability of transportation to move that sand into your regions of operation? Or how is that playing out?
Yes. I think it's playing out favorably for the producer, the whole trend towards regional sand. I laughed at early on, say 6 months ago, I was a sand snob and said Northern White only. We don't want to take that risk. But then we're looking just like others.
We've already done some pilots with regional sands that are cheaper, 100 mesh pilots regional sand. And it's so far so good, I would say. And so the whole trend within the industry to seek out regional is going to put less pressure obviously on the Northern White. So 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 Low unemployment is great, but Low unemployment is great, but we and the service companies are seeing it in trucks and trains that some of that is jamming up. And so there are some that are going their own trucking companies just to make sure they can move the product and more focus on transload and so on. So 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 and but now it's focused on the logistics of it. And but we do see 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.