Antero Resources Corp (AR) 2018 Q1 法說會逐字稿

Good day, and welcome to the Antero Resources First Quarter 2018 Earnings Conference Call and Webcast. (Operator Instructions) 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, and 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 3 special committees are not directors associated with private equity. All 3 special committees have hired financial and legal advisers 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 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'm going to highlight our operational execution during the quarter, including the significant efficiencies and the 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 payouts that we expect to place in service in the next -- in the second quarter. Glen will then highlight several significant first quarter achievements, including our strong cash flow growth and the 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 this 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 have 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 length by some 8% as compared to year-ago levels.

Now let's quantify what these efficiencies mean from a million-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 represent 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 1 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 #5, titled, Operating Evolution Continues, our well cost by chart shows that nearly 50% of our well costs are locked in through 2019, with our completion crews fully contracted in 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. 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 the sales of 24 wells on these 2 pads within this month with expected production at a combined gross constrained rate of approximately 350 million to 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 2 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 our 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 Bcf equivalent 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 the 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 transformation portfolio that allows us the optionality to move virtually all of our gas to premium markets.

Turning to Slide #6, titled, Appalachia Peer Pre-Hedge 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 first quarter 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 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 have 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 to $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 do 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 #7, propane fundamentals remained strong, with days of supply at the lowest level in 5 years and inventory 24% below the 5-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 towards 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 #8 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, as uncertainty around both Henry Hub gas pricing in Northeast bases is likely to continue.

As a reminder, as shown on Slide #9 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.

Next, I want to touch on the substantial marketing gain we reported this quarter. As highlighted on the Slide #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 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 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 stand-alone adjusted EBITDAX of $488 million, including the marketing gain of 31% increase sequentially and a 52% increase over the year-ago period. Stand-alone adjusted operating cash flow was $433 million, 66% higher than the year-ago period.

Slide #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 first quarter results showcased 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 #12, is at the lowest level in our history at 2.5x on a stand-alone basis.

Leverage is projected to decline further towards 2.0x at the end of this year. As shown on Slide #13 titled, Antero Profile to Drive Multiple Expansion, this momentum will place Antero in an elite group of just 7 E&P companies that have scale, double-digit production growth, low leverage and generate free cash flow. All of them trade at premium multiple valuations relative to Antero.

With that, I will now turn the call over to the operator for questions.

(Operator Instructions) The first question is from Subash Chandra of Guggenheim.

Paul, your dry gas commentary -- 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 1/4 of the drilling program, 20% of the drilling program this year, but are you thinking of waiting 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, it's a good question. We're pleased with the results there in the Utica, but -- and still -- and we're saying 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 -- 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. Now one of your peers in Appalachia, they're contemplating a carveout 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 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?

We -- 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 Drilco, 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. In the long laterals, everyone 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 costs. But 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?

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 drilled longer laterals, of course, we're watching it, and we flat it 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. This is particularly true in the Marcellus, where we've gone out -- our longest completions are in the 14,000 to 14,200 range. In terms of frac efficiency for us, as we frac 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 distant stages. So really still feel good about 14,000-plus on our drilling schedule for this year, and next we are getting longer. We're going out to 15,000 to 16,000, even 17,000 in the Marcellus in some places, and we feel good about it. Truly, 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 plays.

Got it. And a final one for me, and I appreciate your patience. The -- in terms of NGLs -- the summer months, should we anticipate an increase in the proportion of C3+s as a percent of total NGL sales?

I don't think so, Subash. I think it would be fairly consistent increase over the year between C2 and C3+.

The next question is from Welles Fitzpatrick of Johnson Rice.

Actually it's Welles from SunTrust. But on those NGL realizations, thanks for the great macro overview, but as far as the in-base and pricing is concerned, can you talk to the Mariner East outage in March? I mean, did not 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+ pricing in March from that. It's still not back on. As you know, Mariner I, 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 they're very close and just waiting on the regulatory bodies to sign off on the repairs. And as far as ME2, we're still assuming that comes online here midyear, 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 costs to it. We'd estimate if it -- the delay to year-end, it may cost us $30 million 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 that we're making. You say the numbers probably they have 98% of the pipe in the ground and get completed something over 90% of the bores. So they are making progress there. But second quarter is always a bit soft to 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 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've done?

Yes, that's right.

Yes, yes. So we 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 in the gas and liquids plays, we just don't see that decline and 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 the -- our research and looked 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 times in terms of getting the first production, and facilitates drilling those long laterals in the 14,000- to 17,000-foot range, and capitalizing on efficiencies that you get from going out that far, not losing any efficiency on your EUR per 1,000.

The next question is from Brian Singer of Goldman Sachs.

Certainly noteworthy that well costs still 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? 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 the budget for this year. I think there will be some inflation out there if we kind of analyze it -- and show 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 we are able to capture even more efficiency than that, which we fully anticipate doing than 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's a little up to beaten path. Antero's always been aggressive in looking to reduce longer-term pricing risk with the hedges going out into the 2020. 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? Or 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 on the forward curve?

Yes. So as we grow, yes, anyone could make the case for not as much need to hedge. We have about a 2-year, 2.5-year glide with a 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 other part of the curve, and we completed 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 it all or just some portion of it. As to what's out there, on the physicals 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 million a day on those projects, and maybe even another $100 million or $200 million 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 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 shift, 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.

The last question is from Bob Morris of Citi.

Paul, Glen, you sort of fleshed out how you manage the budget with the excess cash flow and the capital gain you had this quarter with a nice improvement in efficiencies if those continue going forward. So the second question I had was just on the sand cost. You said you assume 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 the 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 for the whole trend towards regional sand. I laughed at the -- early on, say 6 months ago, I was a sand snob and said the northern white only. We don't want to take that risk. But then we've -- 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. It's the whole trend within the industry to seek out regional is going to put less pressure, obviously, on 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 on the transportation side, a lot of people, including ourselves, and some of our service companies, are working on that. Low unemployment is great, but we, in 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 to their own trucking companies just to make sure they can move the product and more focused 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 that it's favorable and our bias is that both the sand itself and supply chain are going to help us -- will at least be able to stay flat.

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 to this presentation. You may now disconnect.