Antero Resources Corp (AR) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Antero Resources' Third Quarter 2018 Earnings Conference. (Operator Instructions) Please also note that this event is being recorded.

I would now like to turn the conference over to Mr. Mike Kennedy. Please go ahead, sir.

Thank you for joining us for Antero's third 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 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 for 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.

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 and provide some detail on several of our recently completed liquids-rich pads. Glen will then highlight a number of significant third quarter financial achievements and provide an update on our recent board approved share repurchase plan, which we plan to begin to execute during the fourth quarter.

Let's begin by discussing the efficiency improvements we made during the quarter. Once again, Antero set new operational records during the third quarter. Looking at Slide #4 titled: Drilling and Completion Efficiencies, starting on the top left portion of the slide. In the Marcellus, we held our average drilling days flat at 12 days. And in the Utica, we held that flat at 20 days despite the continued trend of increasing our average lateral lengths in the Marcellus to 10,400 feet in the third quarter.

Completion stages per day in the Marcellus once again set a quarterly record, averaging 5.5 stages per day, including a company record of 6 stages per day in the month of September. This compares to the 4.6 stages per day average in 2017 and 5.0 stages per day average in the prior quarter. These improvements are ahead of our current budget, which assumes 4.5 completion stages per day for 2018. As a result of this improvement, we released 3 completion crews in September as wells are being completed at a quicker pace than the initial development plan.

During the third quarter, we turned to sales several outstanding Marcellus liquids-rich pads. One was an 8-well pad that was drilled with an average lateral length of 9,750 feet and produced a 60-day average rate of over 23 million cubic feet equivalent per well. Even more impressive was the liquid rate, which averaged 1,280 barrels per day of total liquids per well with 25% ethane recovery. In addition, a well in our highest Btu regime was drilled with a lateral length of nearly 12,000 feet and produced a 60-day rate of nearly 26 million cubic feet equivalent per well, including 1,709 barrels per day of total liquids with 25% ethane recovery.

As depicted on Slide #5 titled: Largest Liquids-rich Drilling Inventory in Appalachia, Antero holds 40% of the core undrilled liquids-rich locations in Appalachia, over 2.5x more than our closest competitor. This extensive liquids inventory is a clear competitive advantage compared to our Appalachian peers.

Despite reducing completion crews during the third quarter, we continued to outpace our drilling program. In order to maintain consistent development and capitalize on the attractive liquids pricing environment, we opted to pull forward one of our liquids-rich pads from early 2019 into late 2018. This 9-well pad is expected to have an average Btu of 1,260, which is among the highest Btu regimes in Antero's core Marcellus footprint. The average lateral length at this pad is 13,200 feet, and first production is now targeted for January of 2019. The decision to pull forward the spending on this pad increases our 2018 D&C budget a modest $50 million to $100 million, but also increases free cash flow momentum as we head into 2019 with strong liquids prices. This momentum is further enhanced by the expected start-up of Mariner East 2, which gives us access to premium-priced NGL export markets.

As we detailed on the second quarter conference call, Antero experienced production curtailments during the latter part of the second quarter and into the third quarter due to oil hauling constraints. These constraints were fully alleviated in September as we were able to contract sufficient trucking capacity to meet not only oil production, but also to begin working down the oil inventory surplus on our pads. We estimate that the curtailment negatively impact production by an average 86 million cubic feet equivalent per day during the third quarter. With the trucking contracts now in place, we do not anticipate further trucking constraints and remain on track to achieve full year production guidance.

Now to briefly touch on our 2018 well completion plan. The quicker pace of the development plan resulted in 124 wells being turned to sales during the first 9 months of the year, including 73 wells during the third quarter. This activity level was a record for any quarter in Antero's history that led to a sharp increase in production volumes as we recently surpassed the 3 Bcf equivalent per day production milestone for the month of October.

Further, the quicker development pace during the first 9 months of the year results in only 27 new wells placed to sales during the fourth quarter to complete the 2018 development plan. This more modest completion pace leads to a significant decrease in spending during the fourth quarter, which, when combined with sharply higher production volumes and attractive liquids pricing, is projected to drive considerable free cash flow during the fourth quarter.

Lastly, we are excited to have recently completed our Special Committee process, which results in a midstream simplification. As you are aware, on October 9, AMGP announced a definitive agreement to acquire AM in a stock and cash transaction that is expected to close in the first quarter of 2019.

Slide #6 titled: Summary Simplification Transaction Benefits, highlights the numerous merits of the transaction. The transaction truly is a win-win-win across the Antero family and has been very well received by both upstream and midstream shareholders that we have spoken with.

The transaction simplifies the midstream structure and aligns all equity holders as shown on Slide #7 titled: Antero Simplified Pro Forma Structure. New AM will be structured as a C-corp without IDRs, which we believe is the increasingly preferred structure by midstream investors. And importantly, for AR shareholders, the transaction results in better alignment between management and shareholders. In addition, AR will receive a minimum of $300 million of proceeds that, when combined with AR's targeted free cash flow over the next 12 to 18 months, is expected to fully fund AR's $600 million share repurchase program.

As the longest-tenured management team among our Appalachian peers with significant share ownership, investors can expect a stable and consistent approach in our development plan. We are committed to unlocking per share value through our integrated strategy that delivers attractive returns to our peer-leading liquids-rich asset base.

Entering the fourth quarter of 2018, we expect to begin generating considerable free cash flow, a majority of which will be returned to shareholders during the period. At today's share price, buying back shares is an attractive use of capital as it is highly accretive to NAV.

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

Thank you, Paul. Good morning, everyone. Let me begin with our key financial achievements from the quarter. I'll then shift focus to the fourth quarter, which is a key inflection point for Antero as we begin generating sustained free cash flow and returning a significant portion of that capital to shareholders through our recently announced share repurchase program. I'll also finish by touching on 2019 briefly.

During the third quarter, net production averaged a record 2.718 Bcfe per day, delivering 17% year-over-year growth and 8% sequential growth, including a record 129,000 barrels a day of liquids. Liquids production increased 14% sequentially, reflecting a continued emphasis on developing our liquids-rich acreage. Liquids production included 10,632 barrels a day of oil, 79,819 barrels a day of C3+ NGLs and 38,901 barrels a day of ethane, all new records for Antero.

During the third quarter, Antero's realized natural gas price was $2.95 per Mcf before hedges, representing a $0.05 per Mcf premium to the average NYMEX Henry Hub price. This marks the 17th consecutive quarter that we delivered pre-hedged natural gas realizations at a premium to the Henry Hub per MMBtu price.

Moving on to liquids pricing during the quarter, we realized an unhedged C3+ NGL price, that's propane and heavier, of $38.41 per barrel, representing a 33% increase from the prior year quarter. We expect the strength in NGL prices to continue as we currently forecast ME2 to be operational during the fourth quarter of 2018, which will give us access to the premium-priced international markets. As a reminder, every $5 per barrel increase in NGL prices results in an incremental $170 million in revenue to Antero on an annualized basis.

As shown on Slide #8, our liquids production growth profile, when combined with pricing improvement, drives compounding exposure to improving NGL prices. The outlook for ethane pricing also looks positive with the recent increase in Mont Belvieu prices. If ethane remains economically attractive with the addition of a new 20,000 barrel a day de-eth at Sherwood in the fourth quarter, we have upside to recover volumes of up to an average of 45,000 to 50,000 barrels a day during the fourth quarter, with further upside to 55,000 to 60,000 barrels a day in 2019. To quantify the pricing impact, each $0.10 increase per gallon in Mont Belvieu ethane pricing results in approximately $40 million in incremental revenue to Antero on an annualized basis.

As you can see on Slide #9 titled: A Top U.S. Producer, Antero is the top NGL producer in the U.S. based on full year 2018 consensus estimates and also third quarter numbers, so far, even when compared to the large cap E&Ps and integrated oil companies.

Now I'd like to briefly touch on our financial highlights for the quarter. Antero led its peer group once again in realized pricing as you can see on Slide #10 titled: The Leader in All-In Realized Pricing in Appalachia. Antero generated stand-alone adjusted EBITDAX of $419 million, a 48% increase over the year-ago period. Stand-alone adjusted operating cash flow was $362 million, 63% higher than the year-ago period, driven primarily by higher natural gas and liquids production and favorable liquids prices.

Slide #11 highlights our historical consistency in being a peer leader when comparing stand-alone EBITDAX margin to our Appalachian peer group. Our strategy, integrated strategy, has positioned Antero as a leader in EBITDAX margin for almost 6 years. Our stand-alone adjusted EBITDAX margin was $1.68 per Mcfe, a 26% increase from the prior year period. This outperformance and consistency is a direct result of AR's industry-leading NGL exposure firm transportation portfolio to attractive markets, hedged portfolio and integrated midstream business.

As a reminder, we are the only U.S. producer that is 100% hedged on expected natural gas production for the remainder of 2018 and all of 2019, and we're hedged at $3.50 per MMBtu.

As we have spoken about since January's Analyst Day, the fourth quarter of 2018 is expected to be an important inflection point as we expect to begin generating free cash flow on a sustained basis as illustrated on Slide #12.

As we outlined in our release last evening, we expect to generate $425 million to $475 million of stand-alone adjusted operating cash flow during the fourth quarter. We also expect to reduce consolidated drilling and completing capital spend for the fourth quarter to $200 million to $250 million, which equates to approximately $240 million to $300 million of stand-alone D&C capital spend based on the historical relationship between consolidated and stand-alone D&C spending. When you combine the expected cash flow with the expected reduction in stand-alone D&C capital spend, 1/4 of the $25 million annual land maintenance capital spend guidance for 2018, we expect to generate free cash flow in the $150 million to $200 million range based on our current commodity prices during the fourth quarter of this year.

We like our position as the largest NGL producer in the U.S. as it enables us to take advantage of attractive liquids pricing in the market today. On a stand-alone basis, we anticipate generating a free cash flow yield of approximately 8% in 2019, which, as you can see on Slide #13, would place us at the top among the independent E&Ps.

Lastly, our board recently approved a $600 million share repurchase. And given our discounted valuation on enterprise value to EBITDA and to NAV, we believe this is an extremely attractive use of capital. This share repurchase plan if fully utilized at today's prices results in the repurchase of over 12% of shares outstanding. We expect to be in the market buying shares during the fourth quarter of 2018.

Looking ahead to 2019, based on our previously stated stand-alone D&C capital targets of $1.5 billion to $1.6 billion and assuming current strip prices, we expect at least $400 million in free cash flow next year.

With our share repurchase program in place, we plan to return the majority of our expected free cash flow to our shareholders during the period while exiting 2019 with leverage under 2x. That's 2.0x. In addition to this free cash flow, we also expect a minimum of $300 million of proceeds from the simplification transaction expected to close in the first quarter of 2019 and $125 million in early 2020 expected from the first tranche of the water earnout payments associated with the water drop-down into Antero Midstream. We like where we are today with our ability to take meaningful advantage of what we view as a disconnected equity value.

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

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

As you look at the macro landscape for liquids in Appalachia, has sort of your competitive situation there, has it changed at all as we see the shift from all the Appalachian players to liquids? When do you think the takeaway constraints are an issue again? And how do you navigate that over your 3-, 4-year outlook?

Yes. We continue, Subash, to add liquids-rich acreage. And so we still have the dominant position. Others are drilling theirs up, but we've stayed pretty steady on our inventory. So I think we're just as strong, if not stronger, relative to our peers in the liquids-rich part. We do have some impediments right now on infrastructure. They're pretty short term, whether it's Mariner East or the Hopedale #4 fractionator. We expect both of those to be open for business in the next month or 2 or 3. After that, it's pretty smooth sailing for quite a while, don't see much in the way of logjams over the next several years. Mariner East is built so that it can expand and carry a lot more export capacity. Both the purity lines and the Y-grade lines that go to the fractionators, both at Houston and Hopedale, are in the process of being expanded right now. And so that will give us smooth sailing for quite a while. And then we're just having our next de-ethanizer come on at Sherwood. Sherwood 10 just came on yesterday and the de-eth will be there in a couple of weeks. And then another one in the first quarter of next year. So if you look at all those elements, whether it's processing, de-ethanization, the purity and Y-grade or the fractionators or Mariner East, I think those all get relatively solved over the next 6 months. So don't really see getting jammed up again for quite a long time.

Got it. Okay. And I understand if you don't want to comment on a third-party project, but if you could on sort of the Kinder Morgan project that got canceled earlier this week, I think, or last week, sort of. Was that a reflection that there was, this capacity you're talking about, there was just enough of it or that really the route that producers want to take is the export route versus the Gulf Coast route on the future takeaway?

The export route does get one, a premium to Belvieu, but I think the producers look and see that Mariner East is expandable several times, can really be bulked up. So it's favorable to Belvieu and competitive and it's there. So I think producers are happy to align behind that one. And so the speculation is that Kinder on the one that they -- they're going back to maybe using it as a line reversal for gas instead of liquids, as you know.

Got you. Okay. And if I could just ask one final one. On delevering, I mean, do you feel like any of the maturities need to be paid off or that the path towards sub-2x is all we need to know on the delevering?

Yes. I mean, we assume that the maturities naturally roll off just based on our cash flow forecast using strip commodity pricing. So not a big need to refi those notes. It's possible that it gets more favorable over time, particularly if we move to investment-grade over the next year or so. But right now we just assume the maturities roll off and we put the payoff on to our credit facility, which is quite sizable. So that's the plan right now for AR.

The next question is from Jane Trotsenko of Stifel.

You have been guiding to 60% of WTI for C3+ price realizations for 2018 and 72% of WTI for 2019 through 2021. So given the strong backwardation in both WTI and the NGL forward curve, are you still expecting to achieve 72% of WTI for C3+ in the coming years?

Yes. Jane, this is Mike. Yes, we do expect the same percentages that we've guided to. If you look at the actual byproduct, our barrel, it comes out to those percentages, assuming ME2 is on in the fourth quarter of '18 and obviously on for the time period through 2022.

Okay. So it's Mariner East 2 which will be like the key driver for your confidence in those?

Correct. Yes. When you look at the international pricing, that really gives you an uplift compared to Mont Belvieu pricing. So that really drives that realization increasing over that time period.

Okay. Got it. And then on Mariner East 2 pipeline, there were some reports about possible delay. Could you please update us on the status of the pipeline and if it's going to be brought online in phases?

Well, as Subash just said, there's always a danger of commenting on third-party projects. But our standing is that they're moving along, that it will be brought on in phases with the smaller amounts with their using some of the repurposed bypasses early on that's going to allow production on the order of 150,000 barrels a day. And then once they get it worked out within the next year, then it can expand quite a bit more. So I think 2 phases. The early one is in the next few months. And then the next one after that is within the next year. But again, of course, that's our view from afar. I couldn't say we know more than the general public.

Okay. Okay. Maybe related to this, how should we think about ramp-up in Antero's, let's say, NGL flows on Mariner East 2? Is it going to be like gradual ramp-up in pipeline flows on that pipeline?

I think we assume by January 1, in January 2019, we'll be flowing our 50,000 barrels a day of propane and butane just per our MVC. And then what Energy Transfer has stated is that they plan to have the entire pipeline on by third quarter of 2019. So those are the assumptions that we're using right now, that by 2019 we're able to flow more than 50,000 barrels a day, the MVC, by the third quarter of 2019 and essentially flow all of our liquids to the extent we want to on ME2, all of our propane, butane, that is.

The next question is from Holly Stewart of Scotia Howard Weil.

Maybe just the first one on sort of CapEx trends and all the efficiencies that you guys are seeing. Can you update us on that D&C capital transparency slide? I'm just trying to think through the average stages per day has gone down. So I guess the question, is, is there any changes at this point to highlight on well costs just given those trends?

No. Holly, the $860,000 per thousand feet still holds. We're just obviously doing the stages much quicker than we thought so that the capital has actually been accelerated into earlier periods, but the same well costs.

Okay. And I'm assuming that just the shift that you guys have outlined here today, that TIL schedule still stays?

It does. Yes. The shift of capital will result in wells coming on quicker in '19. That McKim Pad, those 9 wells come on in January of '19 instead of more kind of midyear-ish '19. So that's the change in the well schedule, but the actual TILs for 2018 are unchanged.

Got it. Okay. And then just there's been several pipeline projects where you guys have some capacity that's come on here as of late. So can you just update us on what you're currently utilizing and then what you are still anticipating to come on over the next couple of months?

Yes. Let me go through the list, Holly. So new things that have come on in recent times. A pipe, Columbia pipe called WB. And westbound WB has come on now for their full 800 million a day. So we're utilizing that. And that ties to our Tennessee that was upgraded from 590 million to 790 million a day. So the 800 million more or less ties with the 790 million that goes to the Gulf. So 2 projects there that have just come on. We've upgraded our TCO T system to another 100 million a day. We're using all of that. That goes to the TCO pool. We expect WB eastbound, which goes over to the Cove Point area. We have 330 million a day on that. And that is going to be online as soon as November 15, so just a couple of weeks away. And then one that we're certainly looking forward to that should be within the next month is Rover Phase 2. It's 800 million a day that comes down from Clarington area down to Sherwood. So what that will do is allow us -- we're not shut-in or anything -- but it will allow us to redirect our gas to Chicago and Gulf markets on Rover. That capacity now or those gas volumes are going to Tetco M2 and Dom South. So there'll be an upgrade there on netbacks. And then the next one that is yet to come online is called Mountaineer. It's a TCO TransCanada project. And we have 700 million a day on that. And that's due to come on in January of this year. So I think that's on track, not sure I've missed any, but those are the big ones. And so it allows us both to keep growing and also to redirect our volumes to the better markets.

Yes. No, that's perfect. And then maybe just another, or a bigger-picture question for you. I know you've been focused here as of late on the simplification, but I'm sure you're watching the markets. And we've had a lot of M&A deals happen, gosh, in the last week or so on the oil side. So just kind of curious as to what you're seeing right now in the basin?

Yes, Holly, in the basin, we have seen several deals over the past year. They tended to be smaller deals following the EQT-Rice deal, which was obviously a large deal. But you have had a number of consolidations occurring kind of around the basin, 4 or 5 of them. Wouldn't be surprised to see more of that happen here over the next year. That's certainly the trend, and we agree with that. It makes sense in a lot of cases. So I think you'll see some in Appalachia.

(Operator Instructions) Our next question is from Kevin MacCurdy of Heikkinen Energy Advisors.

Looking at Slide 13, it seems to imply around $400 million of free cash flow to Antero. Just curious what CapEx number that's based on? And does that include the fully burdened water costs?

Yes, it does. The stand-alone CapEx number is kind of $1.5 billion to $1.6 billion. And the consolidated number's $1.3 billion, the difference being the water.

Great. That's certainly compelling free cash flow. And to follow up on an earlier question. Thanks for the clarity on the C3+ prices. Just to get a little bit more color, are you saying that Antero's realizations will be better than Mont Belvieu forward prices?

Yes. I mean, the calculation is not based on Mont Belvieu, it's based on Northwest Europe mainly and where the actual volumes would go. So those are ahead of Mont Belvieu pricing.

Yes, comparing Marcus Hook as the export facility to Belvieu, we expect to see a premium at Marcus Hook compared to Belvieu. That's right.

Thank you very much. Ladies and gentlemen, that then concludes our question-and-answer session. I'd like to turn the conference back over to Mike Kennedy for some closing remarks.

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

Thank you very much. Ladies and gentlemen, this concludes this conference call. Thank you for attending and you may now disconnect your lines.