Antero Resources Corporation (AR) Q4 2017 Earnings Report, Transcript and Summary

Good day, and welcome to the Antero Resources Fourth Quarter and Full-Year 2017 Earnings Conference Call and Webcast. All participants will be in listen-only mode. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Senior Vice President of Finance and Head of Investor Relations. Please go ahead, sir.

Thank you for joining us for Antero's fourth quarter 2017 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 have 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 to the most comparable GAAP financial measures. Before I turn it over to Paul, I also quickly want to address the recently published shareholder letter and our response press release. As stated in our press release, we are currently working with our Board to evaluate various 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. During today's call, we will not address any additional questions related to this matter. Joining me on the call today are Paul Rady, Chairman and CEO, and Glen Warren, President and CFO. I will now turn the call over to Paul.

Thanks, Mike, and thank you to everyone for listening to the call today. In my comments, I'm going to review our 2017 development activity, including the cost efficiencies and targets we have achieved, discuss our unique acreage position and how it will drive stable cash flows through our liquids exposure and our long lateral drilling, and finish with an operational update with respect to Antero's recently announced five-year plan. Glen will then highlight our fourth quarter and full-year financial results including price realizations, provide a brief update on recent marketing activities with our firm transportation portfolio, and discuss further our recently announced five-year operational and financial targets. First, I wanted to quickly touch on our recent Analyst Day that we hosted in New York in mid-January, which many of you have attended. Our decision to put on this event was a reflection of where Antero is today in its lifecycle. Following years of substantial production growth from virtually no production back in 2008 to now the seventh largest gas producer today, we are now moving into the next phase with the focus on disciplined investment and the delivery of free cash flow. We've been able to reduce our five-year capital plan by $2.9 billion due to the benefits of continued efficiency gains and the shift to longer laterals. These cost savings, combined with our large liquids-rich drilling inventory in the Appalachian Basin lead to $1.6 billion of targeted free cash flow through 2022 with upside to $2.8 billion under a $60 per barrel steady oil price environment. This updated five-year outlook positions Antero in a very small group of Elite E&Ps that have the size and scale, the double-digit growth, lower leverage and positive free cash flow. Now let's discuss some of our 2017 development highlights. For the second straight year, we executed our development program ahead of plan and under budget at $1.28 billion, while growing our production 22% year-over-year, including 35% liquids production growth compared to 2016. On the cost front, slide number three, which is entitled, Reduced Cycle Times Lead to Lower Well Costs, the slide illustrates the continued decline in drilling days and the increases in the stages completed per day. In the Marcellus and I want you to focus on the green bars on the diagram, we improved our average drilling days from 15 days to 12 days or 20% reduction, while further increasing our completion stages per day by 5%. These gains both in drilling and completing are particularly impressive given the fact that we increased proppant per foot in completions in the Marcellus by 23% to over 2,000 pounds per foot in 2017 from 2016 levels, while we also increased our lateral lengths. Looking ahead, as portrayed on slide number four, titled, Almost $3 billion Capital Reduction to 5-Year Plan, we've taken approximately $2.9 billion of consolidated drilling and completion costs out of the five-year plan. We'll touch on the components of that in a moment, but as shown on the left-hand chart, the five-year drilling and completion capital budget was reduced from $10 billion to $7 billion, as a result of the new development program. Further, if you look on the right side of the page, you'll notice that we are achieving this significant capital reduction while maintaining our production targets. As illustrated in the purple arrow, we expect to achieve an 18% CAGR from 2018 to 2022, which includes 20% growth through 2020 and 15% thereafter. Now let's break out the components of the $2.9 billion reduction in drilling and completion capital. Slide number five, titled, New Development Plan equals $2.9 billion, D&C CapEx Savings. Slide five contains a waterfall that breaks down the components of the capital reduction. One of the larger components is our focus on longer laterals as shown in the orange bar. As we lengthened the laterals, we spread out the fixed costs of the well and reduce the overall cost per foot. That shift alone to almost $1 billion of capital or just over $1 million per well. The second component illustrated by the purple bar is reduced cycle times. By continuing to reduce drilling days and increasing our stages per day, we were able to eliminate $0.5 billion from the drilling program. This includes further expectations for an increase in stages per day over time and the introduction of concurrent operations where we expect to be able to drill and complete concurrently on separate areas of a pad. The next component of cost savings is a function of our capital allocation with more focus on our high-graded liquids-rich Marcellus over the Utica which removed $1.1 billion of capital. Additionally, we removed over 90 drier locations in the Marcellus, from the previous five-year plan, resulting in a more capital-efficient spending, while still delivering the same production growth. The last piece is simply well cost savings as shown by the brown bar on the right. The $0.4 billion reduction here is primarily driven by the Antero Clearwater Facility, the ability to truck our wastewater a much shorter distance in West Virginia to recycle rather than trucking the wastewater to disposal wells in Ohio. The Antero Clearwater Facility is a viable opportunity because of our unique contiguous acreage position. To further touch on this, I'll direct you to slide number six, entitled Who Has the Running Room? We believe there are two things that separate us from many of our Appalachian peers. First, our contiguous acreage position has allowed us to drill on average longer laterals than anyone in the Marcellus to-date, and gives us the deepest inventory of long laterals in the basin. Second, our peer leading liquids-rich inventory, we control more than 40% of the undrilled locations in Appalachia. We are currently the largest NGL producer in the US and expect to grow our NGL production by 20% annually over the next five years, which gives us tremendous exposure to liquids upside, as Glenn will get into later. This combination gives us significant running room to drill high rate of return wells for many years to come and plays a significant role in our ability to generate meaningful free cash flow. Finally, some operational highlights that we touched on in our earnings release. We are delivering long laterals today as nine of the 27 horizontals we drilled in the Marcellus in the fourth quarter had long laterals that were actually longer than 12,000 feet. Our largest pad to-date in the Marcellus is a 12-well pad with approximately 120,000 feet of drilled lateral that will deliver about 300 Bcf equivalent of pad reserves. This is remarkable and this about the reserves can be delivered from one pad. We are also drilling a nine-well pad right now that is expected to have average lateral lengths of 13,200 feet, which will result in similar reserves to the pad I just mentioned. In the Utica, we placed a 10-well pad to sales at year-end that is currently flowing dry gas at a combined rate of over 200 million cubic feet a day with wellhead pressures in excess of 3,000 psi. In fact we achieved record production of 632 million a day recently in the Ohio, Utica, after running only one rig and completing only 22 wells in the play in 2017. With that, I will turn it over to Glen for his comments.

Thank you, Paul. In my comments today, I will highlight our fourth quarter and full-year financial results, including price realization that benefited from our increased liquids volumes and improved NGL prices during the year, provide an update on some recent marketing gains we have achieved, highlight recent favorable credit rating actions from the rating agencies, and finish up with brief comments on our recently announced long-term outlook including our priorities for free cash flow use. Let me begin with some of the key highlights from the quarter and the year. Production averaged a record 2.35 Bcfe a day for the quarter, an 18% year-over-year increase including over 170,000 barrels a day of liquids. Liquids production included 6,200 barrels a day of oil and just over 101,000 barrels of NGLs. This production outperformance continues to be driven by operational improvements particularly associated with the advanced completions and longer laterals that were more widely incorporated across the development program during 2017. Now to briefly touch on some financial highlights from the quarter, we generated $437 million in consolidated EBITDAX. This represents a 30% sequential increase up over $100 million resulting in a consolidated margin of $2.02 per Mcfe. The sequential increase in EBITDAX was driven primarily by improved liquids pricing, which I will touch on in just a minute. Adjusted operating cash flow was 360 million, sorry $368 million or $1.17 per share. Moving on to realized pricing during the fourth quarter, we realized $2.80 per Mcf before hedges on our natural gas production during the quarter, a $0.13 per Mcf differential to NYMEX Henry Hub and above guidance of $0.15 to $0.20 differential per Mcf. Excluding the negative impact from natural gas contract disputes of $0.20 per Mcf, the average price before hedging would have been $3 per Mcf or a $0.07 premium to NYMEX Henry Hub, and in line with the year ago premium, once again illustrating the strategic advantage of firm transportation portfolio that allows us to move virtually all of our gas away from unfavorable local indices. During 2018, we did not expect a material impact from contractual disputes due in part to an amendment to one of the contracts, additional takeaway capacity and expectation of more narrow regional basis differentials based on current strip futures pricing. For full year 2017, excluding the $0.14 per Mcf negative impact from contractual disputes, we realized a $0.02 premium to NYMEX Henry Hub in line with initial guidance. We realized a natural gas hedge gain of $136 million during the fourth quarter or $0.87 per Mcf of gas produced and $366 million for the full year or $0.62 per Mcf of gas produced during the year. Moving forward, we believe that our firm transportation and hedge book will continue to be competitive advantages for Antero as a certainty - as uncertainty around both overall gas pricing and Northeast basis is likely to continue. As a reminder 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. This is over a $0.70 per MMBtu premium or just over 25% higher than current strip pricing. Providing a bridge across challenging gas markets, a steadily growing supply is adjusted by lumpier growth in demand. Next, I did want to touch on a couple of first quarter items we mentioned in our release yesterday that will impact both production and net marketing expense. On the production front, as a result of the severe winter weather that hit the Northeast in early January and the downstream pipeline rupture as well, we were forced to shut in a portion of our production for a few days. These shutdowns combined with the timing of completions throughout 2018 will result in essentially flat production to the fourth quarter of 2017. We continue to expect to meet our 2018 production guidance of 2.7 Bcfe per day with $1.3 billion of consolidated capital spending. On a very positive note the severe weather resulted in significantly higher gas prices than originally forecast in January and provided us with attractive opportunities to mitigate the costs from our unutilized firm transportation. The significant marketing gain and attractive pricing more than offsets the impact from the production shut-downs for the quarter. As outlined on slide number seven, titled Natural Gas Firm Transportation & Sales Update, due to the mitigation efforts in the early part of the year, we are lowering the high end of our 2018 net marketing expense guidance to $0.125 per Mcfe. And in fact expect to report a net marketing gain in the first quarter of 2018. This is an important highlight as we continue to mitigate our unutilized firm costs that we expect to incur over the next couple of years prior to filling most of our transport with Antero equity production. Moving on to liquids pricing for the quarter, we realized an unhedged C3 plus NGL price of $39.16 per barrel, or 71% of NYMEX WTI, and an ethane price of $0.24 per gallon or $10.02 per barrel in the Northeast. The C3 plus NGL pricing of 71% of WTI during the quarter resulted in realized pricing equal to 60% of WTI for the full year, significantly above initial guidance for the year, which was 45% to 50% of WTI. The improvement in realized pricing was primarily driven by the strengthening of Mont Belvieu pricing relative to WTI. The strengthening of Mont Belvieu pricing was a function of rise and export capacity and volumes narrowing the differential to global LPG prices. Continuing on the liquids topic, and as Paul mentioned earlier, our significant liquids-rich inventory enables us to achieve tremendous growth in our liquids production. Nearly 40% of our product revenue is generated by our liquid stream giving us great exposure to upside in liquids pricing. Now, shifting gears for a quick credit update, I'll direct you to slide number eight titled Positive Ratings Momentum. In early January of this year, both AR and AM were given an investment grade rating of BBB minus by Fitch supported by one, our contiguous liquids-rich acreage position in the core of the Marcellus and the Utica; number two, our best-in-class hedge book and FT portfolio, supporting production and netbacks; number three, our integrated business model with Antero Midstream; and number four, our strong balance sheet with a declining leverage profile. The positive ratings momentum continued last week as S&P provided both AR and AM within an upgrade to BB plus from BB. We believe our momentum towards an investment grade rating speaks volumes to not only the business model we've built, but to our execution to volatile commodity price environments over the years. To discuss our recently extended long-term outlook, I'll direct you to slide number nine, which illustrates our expectations of free cash flow over the next several years. And this is based on year-end strip pricing. We expect to achieve a net production CAGR of 20% on average through 2020, while targeting 15% growth in each of 2021 and 2022. We expect to achieve this growth while generating significant free cash flow. As outlined on slide number 10 titled Cash Flow Growth Drives Dramatic Deleveraging, we anticipate leverage to decline to below two times in 2018 and below two times in 2019 on the status quo basis, assuming all cash flow is used to pay down debt. In summary, we have reached an inflection point in 2018, as we plan to deliver free cash flow, assuming year-end strip pricing in a declining leverage profile. As shown on slide number 11, titled Antero Profile to Drive Multiple Expansion, this puts us in an Elite group, with just 16 big companies that scale double-digit growth, low leverage, and generate free cash flow. The projected free cash flow would result in a free cash flow yield in the range of 9% in 2019 using the current share price, very attractive to - relative to the integrated oil companies and leading large-cap E&Ps. With that, I will now turn the call over to the operator for any questions.

We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Holly Stewart with Scotia Howard Weil. Please go ahead.

Good morning, gentlemen.

Good morning, Holly.

Maybe, the first one, just around your marketing accomplishments during the first quarter, I don't think we've actually think you have a marketing gain since you've been public. So, any specific here you can highlight, and maybe more importantly, can you replicate this again?

Well, it certainly was a strong beginning to the year, and of course, it reflects the cold that hit the Northeast, and so we were able to move not only our gas, but by a lot of distressed third-party gas that couldn't get out of the area. And so we were able to deliver gas to good high markets. So we're talking about Chicago and Michigan, even the Gulf because of self-storage draw-down had good prices through January, and then along the Eastern seaboard too. So, it was really good situation. As we fill more and more of our capacity, we will be able to take advantage of good prices. Will we be able to duplicate that at the beginning of the year, time will tell, but as our production grows, it certainly still is a good strategic advantage for us.

Okay, great. And then maybe just if you have any sort of color on what's on liquids pricing right now, looks like both propane and the butanes have been a little weak as of late. So just curious as to maybe - from a maybe higher macro level what you guys are seeing out there?

Well, we're seeing part of what was driving propane prices higher in the international market where Asian buyers that came back into the market and drove the price of propane up to nearly $0.85 a gallon on the front or at least remainder of Cal 18, I should say balance 2018. And they've quite had some, so you've seen demand has drifted down a little bit as some of the buyers have gone away. So the front, as you're probably aware now our balance 2018 is on order of $0.70 or so. We have about half of our Cal-18 production or propane production hedged right now at pretty good prices, and we're just watching and have some expectations that will move up a little bit again.

Okay, that's great. And then maybe a housekeeping item for Glen, if I could. Just Glen, kind of given Rovers and service in the first quarter, how should we think about the GPNT expense kind of flowing through the year, obviously, 1Q would be up, but just kind of thinking about the trend over the course of the quarters?

Yeah, Holly, I'll take that one. This is Mike. We expect the transport portion from Rover ticks up to about $0.55 per Mcfe for the full year. And that's up from the high 40s, and that's directly related to the Rover impact.

Okay. That's great. Thanks, Mike.

Yeah.

The next question comes from Arun Jayaram with JPMorgan. Please go ahead.

Yeah, good morning. I was wondering if you could help us a little bit with how the completion timing will occur now in 2018, given some of the weather related impacts. I think at Analyst Day, you highlighted something between a 140 and 150 completions, I wondered if you give us maybe a little bit of guidance around how that could trend by quarter in 2018.

The 145 that we referenced in the Analyst Day, it's actually pretty evenly split out through the quarters. It just so happens in the first quarter, the majority of that activities occurring in March. So you'll get a full impact from the first quarter completion starting in the second quarter, and that was as scheduled, a bit delay because of the weather, but as scheduled.

Great. A follow-up just on the amendment to the WGL agreement, can you just talk about how that will affect your gas price realizations in the early part and then beyond 2019 what happens?

Yeah. Well, we did restructure part of our contracts with WGL part of the difficulties that they ran into was their ability to receive our gas to buy it at a certain constricted pointer or restricted on the TECO system. And so that was a problem and we had to instead move the gas to inferior markets, lower realizations and realizing some damages. What we've done is to neutralize that contract, so that instead beginning at the end of the year, as WB is completed all the way over to Loudoun, Virginia, we will just be delivering that gas over in the Cove Point area. And so they don't have the restrictions over there to receive the gas. So that's how we worked it out, was reducing and shifting receipt points. And so we don't see that big differential going forward, and I think that that issue will be minimized.

Great. Thanks for that. And just final question is just kind of going back to the Analyst Day. You guys highlighted about $1.3 billion per annum in D&C spending on a consolidated basis between 2018 through 2020. One of the questions we've gotten is just can you help us maybe reconcile that because your lateral lengths are kind of increasing kind of 8% to 10% between 2018 and 2020, or in a bit of an inflationary environment, and you do have a higher completed well count. So maybe just give us a bit of comfort level on the $1.3 billion of D&C spending between 2018 and 2020?

Yeah, and we have put out a new slide yesterday, and it's in the, I think the presentations label CS summit and it's page 48. So it's in the appendix, but there's a slide there that takes you through each year. And you can see part of the difference is it's really driven by the wells that you're working on during the year, not so much the wells that are completed because you may complete a well in January, but the cost really happened in the previous year, and so on and so forth. So this slide kind of takes you through that and normalizes for the wells that are actually being worked on in a given year. And then it also points out that we are assuming some pick up in stages per day going from 4.5 this year to 5.5 over that three years kind of ratably, and then also we do have some concurrent operations baked in there. So you can see those numbers and then it nets you down to that average of $1.3 billion a year, but check out that slide on the CS Energy summit presentation yesterday page 48.

Thanks a lot. Appreciate that.

Thank you.

[Operator Instructions] The next question comes from Jeoffrey Lambujon with Tudor, Pickering, Holt & Company. Please go ahead.

Good morning. Thanks for taking my question. As you get to the free cash flow you highlight, how do you prioritize your options when it comes to using what you generate? You talked about leverage targets, but how do you balance drilling versus inventory adds versus shareholder returns?

Yeah, we like our drilling plan. So no plans to change that relative to what we said at the Analyst Day. And what we said at Analyst Day was we are prioritizing deleveraging at the current time, but we're also very focused on shareholder return. So, it will be a balance of those and we'll see how things play out. There is some sensitivity to that cash flow, could be quite a bit higher with higher liquids prices, could be a bit lower if liquids prices get lower. So this is something we'll just have to determine quarter-by-quarter, year-by-year, but the good news is there is - there's a nice bucket there, nice sized bucket capital to allocate.

Thanks.

This concludes our question-and-answer session. I would like to turn the conference back over to Michael Kennedy for any closing remarks.

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

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.