Michael N. Kennedy - Antero Resources Corp. Paul M. Rady - Antero Resources Corp. Glen C. Warren Jr. - Antero Resources Corp..

Subash Chandra - Guggenheim Securities LLC Jane Trotsenko - Stifel, Nicolaus & Co., Inc. Sean M. Sneeden - Guggenheim Securities LLC Glenn Hank Greenberg - Brave Warrior Advisors LLC Kevin M. MacCurdy - Heikkinen Energy Advisors LLC.

Good day, and welcome to the Antero Resources Second Quarter 2018 Earnings Conference Call and Webcast. Please note this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Vice President of Finance and Head of Investor Relations. Please go ahead..

Thank you for joining us for Antero's second 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 home page 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'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 to the most comparable GAAP financial measures.

Before I turn it over to Paul, I also quickly want to provide a brief update on the review of potential measures to enhance Antero's valuations.

As we have mentioned, a special committee of independent directors of our board in conjunction with legal and financial advisors is conducting this review and working with the special committees of Antero Midstream and Antero Midstream GP boards and their advisors.

The special committees are exploring the full range of options to create long-term value for the stakeholders of all three entities, which is a complex process and remains ongoing.

While substantial progress has been made by the special committees, as we stated previously, 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 a result of this review.

We hope to be in a position to give you an update before the end of the third quarter. As you can understand, we will not be able to address any questions related to this review 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 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 an update on the 2018 completion schedule. Glen will then highlight several significant second quarter financial achievements and updates to our 2018 guidance.

Let's begin by discussing the efficiency improvements we made during the quarter. Once again, Antero set new quarterly operational records during the second quarter.

Looking at slide number 3 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 flat at 20 days despite the continued trend of increasing our average lateral length as seen on the lower-left portion of the slide.

During the quarter, we drilled the longest lateral drilled to-date in West Virginia at 15,100 feet sideways. Completion stages per day in the Marcellus averaged 5.0 stages per day during the second quarter, including a company record of 5.5 stages per day in the month of April.

The trend continues with 6.5 stages per day completed overall on average in late July. This compares to 4.6 stages per day average in 2017. In the Utica, we completed 5.4 stages per day on average, an increase from 5.1 stages per day on average during the first quarter.

These improvements are reducing well costs and are ahead of our current budget which assumes 4.5 completion stages per day. As a result of this improvement, we plan to release two completion crews during the second half of 2018 as wells are being completed at a quicker pace than the initial development plan.

The decision to drop these crews also reflects our commitment to maintaining capital discipline as full year capital spend guidance remains unchanged. The quicker pace of the development plan will result in 65 to 75 wells being turned to sales during the third quarter with an average lateral length of approximately 9,500 feet.

We recently placed into service our largest pad to-date in the Marcellus at 14 wells, which follows two recent 12 well pads turned to sales in the second quarter. As we continue to increase our pad size and lateral lengths while making strides in drilling days and stages per day, we expect to achieve further efficiencies.

We also recently achieved our first remote completion where we located completion crews and equipment on a separate pad from the well pad, enabling improved logistics for completions operations.

In the coming quarters, we will conduct our first concurrent operations where we drill wells at one end of a large pad, while we complete wells at the other end of the pad, thereby getting to first production much quicker on these 8 to 14 well pads. Turning to well costs, earlier this year, there was considerable concern over service cost inflation.

But given the continued efficiency gains by the industry and the constraints that are occurring in the Permian, service costs have recently softened.

Additionally, we continue to assess various self-sourcing sand options which, as the largest component of our well costs, has the potential to save us upwards of $500,000 per well over the long term once we fully implement it.

Despite this operational momentum, we are experiencing some production curtailments due to tightness in the local crude trucking takeaway market. Our crude buyers have been challenged to secure adequate numbers of licensed truck drivers and trucks to move our growing crude production.

We expect these curtailments to be temporary in nature as we have recently executed direct agreements with additional companies for additional trucking capacity. The additional capacity will enable us to lift existing curtailments as well as to move the 100,000 barrel-plus crude inventory that has built up over the last couple of months.

Currently, there is approximately 100 million cubic feet equivalent per day of production that's under curtailment, including 4,000 barrels a day of NGLs and 2,000 barrels a day of crude oil.

With trucking capacity expected to match oil production beginning in September, we anticipate that the production curtailment will be alleviated by the fourth quarter of 2018. In the Utica, five horizontal Ohio wells were placed to sales during the second quarter with an average lateral length of 15,900 feet.

Antero also set a new company record for the Utica, drilling nearly 5,200 lateral feet in a 24-hour period. Additionally, the 10 Ohio dry Utica wells that were completed at the end of 2017 continue to show strong results, producing 200 million cubic feet a day flat over the first 150 days before exhibiting natural decline.

While we remain excited about the Ohio Utica, we have shifted our second half 2018 development plan to more economic liquids-rich locations in the Marcellus due to the continued strength in liquids pricing. However, our current five-year plan does include the resumption of drilling and completion activity in the Ohio Utica in 2019.

Now to briefly touch on our 2018 well completion plan. We remain on track to complete approximately 145 wells this year with an average lateral length of 9,700 feet.

Due to efficiencies, our completions outpaced our production facilities and tie-in line dates, resulting in capital spend in the second quarter that preceded the production benefit that we will see in the third quarter.

As a result, we anticipate in a reduction in Antero's quarterly run rate capital spend during the third and fourth quarters of this year. Nonetheless, our development plan is forecast to result in strong fourth quarter production providing momentum into 2019. With that, I will turn it over to Glen for his comments..

Thank you, Paul. Good morning. Let me begin with our key financial achievements in the quarter and provide color on the changes to guidance we outlined in our press release issued yesterday afternoon.

During the second quarter, net production averaged a record 2.52 Bcfe per day, delivering 15% year-over-year growth and 6% sequential growth, including a record 113,600 barrels a day of liquids. Liquids increased 10% sequentially reflecting a continued emphasis on developing our liquids-rich acreage.

Liquids production included 6,900 barrels a day of oil, 70,500 barrels a day of C3+ NGLs, and 36,200 barrels a day of ethane. During the second quarter, Antero's realized natural gas price was $2.83 per Mcf before hedges representing a $0.03 per Mcf premium to the average NYMEX Henry Hub price.

This marks the 16th consecutive quarter that we have delivered pre-hedged natural gas realizations at a premium to Henry Hub.

During the first half of 2018, Antero's average natural gas price realizations resulted in a $0.09 per Mcf premium to NYMEX before hedges, highlighting the continued benefits from our strategically advantaged firm transportation portfolio.

During the third quarter, we also anticipate Rover Phase 2 capacity to be placed into service, which will unlock optionality to reach the favorably priced Chicago and Gulf Coast markets with either Marcellus or Utica gas further reducing our exposure to local markets.

As a result, we are raising our full-year realized natural gas price guidance from a range of $0.00 to $0.05 per Mcf premium to NYMEX to a range of $0.05 to $0.10 per Mcf premium to NYMEX before hedges. Slide number 4 captures the favorable shift in geographic exposure that we anticipate in the second half of 2018.

As shown in the chart at the top half of the page, we expect a decrease of 5% of our gas being sold in local markets and an 8% increase in Midwest and Gulf Coast markets combined.

As a result, approximately 97% of our gas is expected to be sold into premium markets enabling us to maintain the exceptional natural gas price realizations we achieved during the first half of the year.

Moving onto liquids pricing during the quarter, we realized an unhedged C3+ NGL price of $34.81 per barrel, representing a 44% increase from the prior year quarter.

While NGL prices did not keep up with the rise in WTI prices during the quarter averaging just 51% of NYMEX WTI on an absolute basis, NGL prices remained consistent on $1 per barrel basis with our guidance early this year.

For the full year, we are reducing our full year 2018 guidance for C3+ NGL prices as a percentage of WTI from a range of 62.5% to 67.5%, down to a range of 57.5% to 62.5% due to the delayed in-service date of Mariner East 2 pipeline.

For additional context, if ME2 had been online during the second quarter of this year, we would have received a $4 per barrel uplift on our C3+ realized pricing, which speaks to the significant benefit of this project, particularly in the summer months when NGL differentials are typically wider.

We currently forecast ME2 to be operational during the fourth quarter of 2018, but we also recognize that there is a potential for it to be in-service before that as they are currently working on repurposing an existing product pipeline to move volumes prior to the final regulatory approval and construction completion of ME2.

This is only about a 5-mile segment of ME2. As shown on slide number 5, propane fundamentals remain strong with days of supply at the lowest level in five years and inventory 12% below the five-year average.

Further, as illustrated on slide number 6, based on strip pricing through the balance of 2018, tightening inventories and increased exports are expected to result in an improvement in C2+ pricing through year-end this year.

It's important to note that despite reducing the percentage range relative to WTI, the implied absolute C3+ NGL price, based on our updated guidance, reflects an increase of $1.20 per barrel at the midpoint relative to our January guidance.

The outlook for the second half 2018 ethane pricing also looks positive with recent increases in Mont Belvieu prices. If ethane remains economically attractive, we have upside to recover volumes during the second half of 2018 up to an average of 45,000 to 50,000 barrels per day.

To quantify the pricing impact, a $0.05 increase per gallon in Mont Belvieu ethane pricing would result in $10 million to $15 million in incremental cash flow during the second half of 2018 to Antero.

As you can see on slide number 7 entitled Leader in Leverage to NGL Prices, Antero is a top 3 NGL producer and was the number 1 NGL producer in the U.S. in the second quarter based on numbers released today.

In conjunction with the Mariner East 2 pipeline delay, we are also lowering our full-year cash cost guidance for 2018 from a range of $2.10 to $2.20 per Mcfe on a standalone basis down to $2.05 to $2.15 per Mcfe.

Net marketing expense guidance for 2018 is unchanged at $0.10 to $0.125 per Mcfe with the second quarter as expected, reflecting the high point of the year. We expect net marketing expense to trend lower over the second half of this year as production increases and we begin flowing volumes on the Rover Phase 2 Sherwood Lateral.

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 number 8 titled The Leader in All-In Realized Pricing in Appalachia. Antero generated standalone adjusted EBITDAX of $335 million, a 25% increase over the year-ago period.

Standalone adjusted operating cash flow was $279 million, 36% higher than the year-ago period, driven primarily by higher natural gas production and favorable liquids prices.

As forecasted, we anticipate a return to free cash flow in the fourth quarter of this year, an inflection point for free cash flow that we expect to be sustained throughout 2019. Slide number 9 highlights our historical consistency in being a peer leader when comparing standalone EBITDAX margin to our Appalachian peer group.

Our integrated strategy has positioned Antero as a leader in EBITDAX margin for the past 5.5 years. This outperformance and consistency is a direct result of AR's industry leading liquids exposure, firm transportation portfolio to attractive markets, our hedge 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. In summary, we continue to differentiate ourselves by executing on our long-term strategy.

We remain committed to creating value for our shareholders by focusing on our extensive liquids-rich inventory and delivering on our long-term targets, including a declining leverage profile to the low 2s by year-end this year as shown on slide number 10.

As shown on slide number 11, titled Antero Profile to Drive Multiple Expansion, this momentum will place Antero in an elite group of just six E&P companies that have scale, double-digit production growth, low leverage, and generate free cash flow, all of whom trade at a premium multiple valuation relative to Antero.

With that, I'll turn the call over to the operator for Q&A, for questions..

Okay. Thank you. The first question comes from Subash Chandra with Guggenheim. Please go ahead..

Yeah. Thanks. Good morning. Question on the Utica for you, Paul. And I think Glen concluded his comments talking about liquids-rich, et cetera.

I get it's in your five-year plan, but do you need to reinitiate activity in the Utica at all or do you think you can bypass it to a more active Marcellus development?.

Yeah. I think the latter. I think we have it penciled in for next year, but we're always judging these things based on gas prices and liquids prices. So, there's no obligation to go over to the Ohio Utica side. No leases to say, for example. So, we have flexibility there..

Okay.

And are there sort of hooks in the Utica asset that would keep it in the portfolio or could it be deemed as non-core, if you don't need to develop it?.

Well, we like the inventory and it still gives us a respectable rate of return. So, there are no hooks that would say it's sacred, but it fits in our plan for now..

Okay. Got it. The efficiencies you talked about, just curious if that was really correlated to the larger pads in the quarter or are these efficiencies durable if you go to smaller pads or if you drill regardless the pad size? Yeah..

I think it's both. The larger pads definitely helps, but even for same-size pads we're getting faster and faster..

Great. And a final one for me.

The midstream expenditures at the AR level, facilities gathering, et cetera, what is the outlook for that in the second half? Is it also front-end loaded?.

No. The actual Midstream facilities are not. That's actually borne by Antero Midstream. They're responsible for putting in all those facilities, so that's more straight-line across all the quarters..

Okay. Thanks..

Thanks, Subash..

Thank you..

Okay. The next question comes from Jane Trotsenko with Stifel. Please go ahead..

Good morning. Looking at slide 4, your Midwest exposure will increase from 16% during the first half of 2018 to 23% during the second half of 2018.

With ET Rover and Nexus pipelines coming online and then increasing Canadian natural gas production that also targets the Midwest market, how do you think the regional supply-demand dynamics will evolve with this growing gas-on-gas competition, and if you think that Marcellus gas will be able to push out Canadian gas supply?.

Yeah. So, yes, the reason that more gas is going to go to the Midwest is because the Sherwood Lateral portion of the Rover project will finally reach Sherwood processing plant. So, we'll move more volume in that direction towards Chicago, Michcon, and the Midwest.

And yes, that's what we've seen so far this year is that Marcellus/Utica gas is cost advantaged, and so it is pushing gas. So, Mid-Continent gas is not coming to Chicago, nor Rockies gas nearly as much or to Dawn over in Ontario.

So the Northeast gas is pushing back and displacing gas from Canada, from the Rockies and from the Mid-Continent and I think it will continue..

Thanks. My second question you have several pipelines are just coming online over the second half of 2018 and early 2019.

Could you please remind us the thought process behind which pipelines are going to be filled first?.

So, we do have several pipes coming on. I mentioned the Sherwood Lateral. And so that's an important one for us. We have three projects with TECO, so Columbia. There's the eastbound WB line which goes over to the Washington, Baltimore area.

There's westbound WB that connects with our Tennessee to the Gulf, and then there is MXP which is an important project for us that goes right through the heart of our acreage. And so, we project to be filling all of those over the next 15 months or so. We do look on a best net-back basis on a day-to-day basis, our marketing group does.

And we also judge third-party marketing opportunities on a day-to-day basis. So, we move anywhere from 300 million to 600 million a day recently of third-party gas where we collect a margin of between $0.30 and $0.60. So, we juggle all that.

We weigh all that to see what our best net-back is going to be and where the opportunities are for filling the remainder with third-party gas until we fill it with our own, which is the longer-term plan..

That's it from me. Thank you so much..

Thank you..

Thank you..

Okay. The next question comes from Sean Sneeden with Guggenheim. Please go ahead..

Hi. Thank you for taking the questions..

Hi, Sean..

Maybe just on ethane, I think you guys studied that potential recovery of I think up to 45,000 a day.

What's kind of the threshold on price where it starts to make sense for you guys to start recovering more?.

Yeah. So the broad answer would be in the low $0.30 range to the mid to high $0.30 range. And so, what we're balancing is the local gas value as well. So we have the option to leave ethane in the stream and collect the gas value of the ethane on an MMBtu basis. So as regional gas prices change, that also dictates.

And so, that's why there's a range there on with the ethane price is because we can choose to leave it in the stream or we can choose to recover it. But that's the broad answer is anywhere from say $0.31 to $0.36 is the threshold for where we can elect to recover it and make a profit..

And we have actually capitalized on that a bit recently, incrementally recovering about 7,000 barrels a day in July and August over of what we had planned to recover, just to capitalize on some high pricing in the high $0.30 range per gallon..

Great. That's helpful. And then just lastly for me, a bunch of your bonds are currently callable.

How do you think about potentially trying to refinance some of the front-end maturities? Is that something that begins to make sense or is that something that you need to, or you have a preference to wait until you get to investment grade?.

No. We're always opportunistic. So, that's something we continually watch. And we haven't seen any of them move to the point where we felt like we could execute a bond deal that made sense from an NPV standpoint to pay the premium to call the bond.

But we watch that continually, and I think you'll see us do some of that over time over the coming quarters..

Great. Thanks so much, guys..

Yes. Thanks, Sean..

Okay. The next question comes from Glenn Greenberg with Brave Warrior. Please go ahead..

Good morning, Glen, and good morning, Paul..

Hi, Glenn..

Earlier this year, there were special committees formed just to discuss the structure of the general partnership and the midstream assets and AR, the exploration company. I'm wondering what's become of those discussions.

What was the objective behind having them in the special committees being formed and kind of where did your deliberations take you to this point?.

Well, the deliberations continue, Glenn. And so, it's serious discussions. They're very deliberate and the special committees move carefully to make sure that all bases are covered. Each special committee has advisors, legal and financial. And the big picture has been simplification.

And I think the market has looked and seen which could be combined with which and what levers could be pulled. And so, that's been out there, but that's all we can say. Of course, no guarantee that anything will happen but serious discussions continue to happen..

Thank you..

Okay. I have a question from Kevin MacCurdy with Heikkinen Energy Advisors. Please go ahead..

Hey, guys. I saw that you mentioned that you are dropping two frac crews in the Appalachian region. I'm wondering what this means for future well cost and if maybe we could see some lower CapEx in the future if operations are more efficient..

Well, the delta really there that you're looking for is just more stages per day rather than the number of frac crews. So, we needed pure crack frac crews because we front-end loaded our completions partly this year but also because of that increase and that was driven partly because of the rate of increase.

We had budgeted 4.5 stages per day and now we've seen 5.5, even 6.5 in late July. So we just need fewer crews. But for every increase in stages per day on a well, you pick up $90,000 to $100,000 of well cost savings. So, that's kind of the magnitude. If we can average 5.5, say, the rest of the year, we'll save almost $100,000 per well..

And will you add back crews for next year or is this kind of the four crews will be enough to execute your 2019 plan?.

No, I think we'll be adding back and we'll make a judgment call as to how many and when. As Glen said, it is an efficiency factor, so we'll see what our current state of affairs is at the end of the year or in the fourth quarter and how many stages we can accomplish per day and make a judgment call there.

But as we get faster and faster, these crews can accomplish more in a shorter amount of time. And the way the contracts are structured, there is a price break. They are covering their base load equipment. And then as they get more stages off, they make more money but the price per stage goes down..

All right. Thanks for the clarity..

Yeah. Thank you..

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

Thank you for joining us on today's conference call. If you have any further questions, please feel free to contact us. Thanks again..

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