Antero Resources Corp (AR) 2016 Q1 法說會逐字稿

Good morning and welcome to the Antero Resources first-quarter 2016 earnings conference call.

(Operator Instructions)

Please also note this event is being recorded. I would now like to turn the conference over to Michael Kennedy, Senior Vice President of Finance and Investor Relations.

Please go ahead, sir.

Thank you for joining us for Antero's first-quarter 2016 investor conference call.

I will 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 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.

Joining me on the call today are Paul Rady, Chairman and CEO, and Glenn Warren, President and CFO. I will now turn the call over to Glenn.

Thank you, Mike.

And thank you to everyone for listening to the call today. In my comments, I'm going to highlight our first-quarter financial results, including price realizations and EBITDAX margins and then touch on the capital markets activity during the quarter, as well as our financial flexibility.

Paul will then highlight the significant operational improvements we achieved during the quarter, including service cost reductions and operational efficiency gains that continue to drive down our overall development costs, and finally discuss the operational flexibility of Antero.

During our comments, both Paul and I will periodically refer you to a handful of slides that are located in a separate conference call presentation on the home page of our website titled, First-Quarter 2016 Earnings Call Presentation. This is separate from our Monthly Investor Presentation, also located on our website. So please make sure that you are reviewing the correct slide deck during the call.

Let's begin with some of the key highlights from the quarter, as we had another tremendous quarter both operationally and financially.

Production averaged a record 1.758 Bcfe per day for the quarter, including over 68,000 barrels a day of liquids. This outperformance during the quarter, combined with the continued operational efficiencies we are seeing today, enabled us to increase production guidance for the year to 1.75 Bcfe per day, while still maintaining our $1.3 billion drilling and completion budget.

The liquids production during the quarter included approximately 12,000 barrels a day of ethane, which was a significant increase from the 2,179 barrels a day of ethane we recovered in the prior quarter, as this was the first full quarter following the installation of a deethanizer facility at the Sherwood complex in December of last year. While we are only recovering approximately 12,000 barrels a day of ethane today, the deethanizer does provide capacity to recover 40,000 barrels a day of ethane at the Sherwood facility, providing us with the ability to significantly increase ethane production in the event that ethane prices continue their recent upward trajectory and local economic support recovery.

Moving on to realized pricing during the quarter, despite the continued downward pressure on commodity prices, we realized all end pricing at $4.14 per Mcfe, including NGL's oil and hedges, which was a $2.05 premium to the Nymex average during the quarter. The ability to realize prices at a premium to Nymex was a function of our industry-leading hedgebook, along with our diversified firm transportation portfolio, allowing us to sell approximately 99% of our natural gas production at favorable price indices, an improvement from 83% in the fourth quarter.

In fact, we sold our natural gas at a $0.01 differential to Nymex on average for the quarter before hedges. As you can see on slide 2, entitled Hedge Strategy Produces Consistent Results and Stability, we realized a hedge settlement gain of $324 million during the quarter or $2.03 per Mcfe.

Since 2009, we have consistently realized quarterly hedge gains, including 28 of the last 29 quarters. Looking ahead as of March 31, 2016, we had 3.6 Tcfe hedged at an average price of $3.71 per Mcfe, resulting in projected hedge gains of $3.1 billion through 2022. This strategy of selling production forward has allowed us to lock in attractive returns and provides us with stability by maintaining momentum via prudent growth through the downturn. This is especially important in an environment where our peers are forced to scale back to preserve capital.

To further discuss our firm transportation portfolio, I will refer you to slide 3, titled Projected Incremental EBITDA from Stonewall. This quarter represented the first full quarter that we had access to the Stonewall pipeline, which enabled us to sell approximately 99% of our natural gas production at favorable priced indices, as I mentioned earlier. As you can see on the map on the right-hand side of the page, Stonewall allowed us to shift all Marcellus production that was otherwise flowing north to Dominion South and TETCO in tube pricing down Stonewall, enabling us to received favorably priced TCO at Nymex-based pricing.

Based on 2016 guidance, this will result in a 650 million Btu per day shift in volumes in 2016 and an incremental $126 million in EBITDA, as you see at the lower left-hand side of the page. Bolstered by the previously-mentioned hedge gains, coupled with the price realization improvements, we generated $355 million in (inaudible) EBITDAX during the quarter.

As you can see on slide 4, titled Highest EBITDAX and Margin Among Peers, despite a decline in Nymex gas and oil prices of 30% and 32%, respectively, AR's EBITDAX was essentially unchanged year over year. This translated into EBITDAX margin of $2.03 per Mcfe for the quarter, which we expect be the highest among our peers during the quarter once again as we continue to benefit from our hedge book and FTE portfolio.

Before moving on to our 2016 development plan and balance sheet, I wanted to touch on net marketing expenses. During the quarter, we generated $99 million in marketing revenue, along with marketing expenses of $138 million. The largest component of marketing expense was demand charges associated with unutilized capacity and third-party gas purchases. During the first quarter, we purchased and sold approximately 540 million cubic feet a day of third-party gas, utilizing excess capacity on the Tennessee Gas Pipeline and capturing an average spread of $0.43 per Mcf.

Net marketing expense was in line with expectations, at $39 million or $0.24 per Mcfe. As previously discussed, beginning July 1, 2016, and continuing until the Rover pipeline is placed in service, or December 31, 2018, whichever is later, the third party is assuming our ANR pipeline capacity costs.

Looking to the second half of 2016, we expect to see a reduction in net marketing expense as a result of the ANR pipeline costs being covered by a third-party. Said another way, we expect net marketing expense to be more front-half-weighted this year, with first-half 2016 marketing expenses making up approximately 65% of the total net marketing expenses for 2016.

To touch on our differentiation versus our peers, slide 5, titled Continued Measured Growth, illustrates our leading position for growing both production and cash flow. Additionally, looking at the bottom half of the page, you can see that our leverage at year-end 2015 was 3.7 times, which is at a level we feel comfortable allowing the balance sheet to flex in a severe commodity price downturn.

Based on 2016, consensus estimates are leveraged by year-end 2016, it's expected to be essentially unchanged due to the production and cash flow growth I just discussed. This is a key differentiator versus some of our peers, who continue to see declining cash flow leading to increasing leverage from the current commodity price environment.

With that being said, we would ultimately like to see leverage in the 2 times range, assuming a more normalized commodity environment over the long term. Now that we have covered the ability of the balance sheet to support the growth at AR, I want to further expand on the current development plan by highlighting the operational flexibility we?ve built into the program to react to commodity price changes over the next few years.

Directing you to slide 6, titled Low Maintenance Capital Provides Flexibility and Upside, you can see that we could spend just $275 million of drilling and completion capital, to maintain production at 2015 levels of approximately 1.5 Bcfe a day. Obviously, we're ahead of that today. Building upon that maintenance capital, you will note that we could also achieve 17% year-over-year net production growth for 2016, while only spending $675 million in total; significantly below the projected hedge revenues in 2016 of over $1 billion. And that is the red line on the left side.

However, in order to continue momentum heading into 2017, our 2016 DNC budget includes an additional $625 million that will contribute to the 2017 growth target at 20%, which we feel very confident about given the continued capital efficiency, flexible DUC inventory and volume sold forward at attractive prices.

Looking ahead to 2017, our maintenance capital needed to generate production levels similar to 2016 would be just $500 million, and that's the yellow box (see slide 6). Almost $100 million below the projected hedge revenues in 2017.

The remaining capital to achieve 20% year-over-year growth in 2016 would be an additional $375 million or $875 million in total. And that is the top of the green bar (see slide 6). And additional capital invested with continued growth momentum into 2018, so about half the capital for maintenance in this year's growth and half for next year's growth.

Now that we've established the ranges in capital spending that allow us to maintain production or continue our momentum to thrive as prices recover, let's move on to slide 7, titled Flexibility and Upside.

First and foremost, we have kept our lean workforce intact throughout the commodity downturn, which provides us the ability to quickly react to changes in commodity prices. For example, we were running 21 rigs in early 2015 with essentially the same workforce, or three times the amount of rigs planned for 2016.

On the midstream front, we benefit from having an in-house midstream provider, Antero Midstream, which can quickly adapt to changes in development plans to avoid gathering compression bottlenecks that could materialize with third-party midstream providers. Our substantial inventory, with over 3,600 remaining 3P locations and the demonstrated ability to efficiently develop the resource, provides significant leverage upside as commodity prices recover.

Said another way, while our peer leading hedge book totals 3.6 Tcfe, and provides a significant downside protection from commodity prices, the upside is truly in the 37.1 Tcfe 3P base and the fact that we are well positioned to develop it. It's also worth noting that our hedge prices of $3.57 and $3.91 per Mcfe, in 2017 and 2018, are 20% and 30% above current Nymex natural gas pricing in those years, respectively.

Moving on to the capital markets for the quarter, we completed an underwritten secondary offering of $8 million AM units for net proceeds of approximately $178 million. In essence, this transaction was monetizing a portion of the roughly 12 million AM units AR received as partial consideration for the water dropdown that AR had not originally anticipated owning, but took as part of the transaction given the challenging environment. And that was in September 2015.

We continue to see tremendous value in the Midstream business, which boasts some of the highest distribution growth in distributable cash flow coverage ratios in the entire MLP space. Pro forma for the offering, we still own approximately 62% of Antero Midstream.

To quickly discuss balance sheet and liquidity, despite the continued decline in commodity prices, our borrowing base under was reaffirmed at $4.5 billion this spring. As you can see on slide 8, titled 2016 Borrowing Base Reaffirmed, Antero was one of only five public E&P companies with a borrowing base greater than $1 billion that did not receive a reduction in borrowing base in a redetermination season this spring so far. And one of only two double B rated public E&P companies that reaffirmed its borrowing base.

The reaffirmation of the borrowing base is a direct result of the significant PDP reserve growth and significant value of our hedge position. As of March 31, 2016, we had over $3 billion of availability under our credit facility and over $3.5 billion of available consolidated liquidity. Additionally, we maintained stable debt and leverage levels from year-end 2015.

Looking forward, we expect to continue delivering top-tier production growth, with 17% year-over-year growth guided to in 2016 and 20% growth targeted for 2017.

With that I'll turn it over to Paul for his comments.

Thanks, Glenn.

In my comments today, I am going to discuss well costs and operational improvements we've seen during the first quarter, including highlighting several new Antero records that we have set. I will finish with a review of our well economics, which illustrates the benefit of deploying capital to generate strong rates of return.

First, let's discuss the significant improvements in well cost that we are seeing. As illustrated on slide 9, entitled Proven Track Record of Well Cost Reductions, current well costs in the Marcellus have declined to $0.95 million per thousand feet of lateral, or a 32% decline, compared to the fourth quarter of 2014.

As you can see on the bottom of the slide, we have seen similar success in the Utica, with well costs totaling $1.14 million per 1,000 feet of lateral, or a 29% decline compared to the fourth quarter of 2014. Not only did the first-quarter 2016 well costs represent significant reductions compared to the end of 2014, the Marcellus and Utica well costs represented a 17% and 13% reduction, respectively, compared to well costs assumed in our year-end 2015 reserves.

The reduction in well cost is driven primarily by reduced service costs, as legacy contracts continue to roll off and we began to realize lower spot rates, as well as a number of operational efficiencies. Let me talk about those operational efficiencies.

If you'll move to slide 10 -- that is a slide called Continuous Operating Improvement -- drilling days during the first quarter in the Marcellus were reduced from 24 days in 2015 to 21 days. And stages completed per day increased from 3.5 stages per day in the prior year to 3.8 stages per day more recently.

In the Utica, drilling days during the first quarter decreased from 31 days in 2015 to 24 days. And stages completed per day increased from 3.7 stages per day in the prior year to 4.4 stages per day. Additionally, during the quarter, we set two new company records.

First, we recently drilled and cased the longest lateral in Company history, at over 14,000 feet sideways. And second, we drilled 5,291 feet of lateral in a 24 hour period, over 1 mile. In fact, all of our top 10 drilling days in the Marcellus since we began in the play have occurred in the first quarter of 2016.

In addition to the drilling and well cost improvements, as you can see in the blue box at the bottom of the slide, during the first quarter of 2016, we obtained a wellhead EUR per 1,000 feet of 2.0 Bcf in the Marcellus shale and 1.6 Bcf in the Utica shale. By fine-tuning profit sizes and modifying the profit mix, we've increased profit placement to over 98% over the last six months. That has been a real focus of ours to make sure that we got the jobs fully off.

While the recent results are very encouraging, we have yet to see the additional improvements from the new completion techniques that I'm going to discuss next. We intend to keep our eye on type curves and economics shown at the 2015 EURs of 1.7 Bcf per 1,000 feet in the Marcellus, and 1.6 Bcf per 1,000 feet for the time being, until we see more results. So that is our current type curves and our current economics that we're sticking with for the time being: 1.7 Bcf per 1,000 feet in the Marcellus, 1.6 Bcf per 1,000 feet in the Utica -- for the time being.

In addition to the improvements just discussed, we recently began pilot testing additional proppant loading and fluid designs in order to improve recoveries and proppant placement. As shown on slide 11 entitled, Marcellus Proppant Placement, we've increased proppant loading by approximately 25% versus our previous design and by fine-tuning the proppant mesh sizes and utilizing 25% more water in completions. We've also been able to hold proppant placement at over 98%.

While based on a small population, the pilot tests on our 2015 vintage wells in our highly rich gas area have responded quite well to the increase proppant loading and placement, exhibiting initial EURs that are 20% to 30% higher than adjacent wells.

Let me move on to slide 12. That is entitled Marcellus Improvements are Driving Value Creation.

This slide is a scatterplot of EURs for all of our 251 Antero, Marcellus, SSL wells completed since 2014. As a reminder, SSL is shorter stage length -- generally 200-foot stage length instead of longer stage length. First of all, you will see that there is a strong correlation between lateral length of the well and the EUR, with no degradation in EURs as we complete wells in the 10,000-foot to 11,300-foot range.

We've completed 33 wells now that are greater than 10,000 feet in lateral length, with EURs averaging just over 2.0 Bcf equivalent per 1,000 feet, just like the EURs for laterals less than 10,000 feet. We have 47 wells in the completion queue today in the 10,000-foot to 14,000-foot lateral length range. This is an important point, as longer laterals improve well economics by spreading the fixed vertical and surface costs over a larger reserve base.

Secondly, the orange diamonds represent EURs for wells completed in the first quarter of 2016. And you can see that they are all on or above the 2.0 Bcf equivalent per 1,000-foot type curves, averaging 2.3 Bcf equivalent per 1,000 feet. Importantly, this outperformance did not yet include the impact of our recent completion modifications to higher profit loading of 1,500 pounds per foot and water utilization of 39 barrels per foot. 2016 will be an interesting year, as we begin to see the results of these larger completions in the Marcellus.

Now, before we move on to the Q&A, I'd like to touch on well economics and the potential upside from the increased EURs that I previously discussed.

Slide number 13, entitled Marcellus Upside Potential, illustrates the impact of improving EURs per 1,000 feet from 1.7 Bcf to 2.0 Bcf in the highly rich gas and highly rich gas/condensate windows seen on wells completed in the first quarter with at least 30 days of production.

As you can see, the increase in recoveries translates into attractive 45% rates of return on a pretax basis in the highly rich gas/condensate areas. And 30% rates of return in the highly rich gas areas, assuming a March 31, 2016 strip pricing or increases of 10% and 6%, respectively. Additionally, these locations have very attractive breakeven prices.

In the highly rich gas/condensate area, where we have over 600 locations, the breakeven price is $1.40 per MMBtu on Nymex gas pricing. In the highly rich gas area, where we have almost 1,000 locations, the breakeven price is $2.05 per MMBtu on Nymex gas pricing. It is also worth pointing out that the well costs that are baked into the returns include $1.2 million for road, pad, and production facilities. And both the demand and variable costs of the firm transportation are also included.

In summary, our first quarter was an outstanding quarter on the operational front. And while we are very pleased with the results, we expect to continue making further progress on improving well costs and returns as we move forward.

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

(Operator Instructions)

Our first question comes from Neal Dingmann, of SunTrust.

Paul, just a question -- towards the end of your comments where you talked about the 10,000-foot wells, looking at the maps -- I just want to make sure I am correct on this -- it looks like you've always had a pretty contiguous position both in the Marcellus and Utica. I guess I'm just trying to think percentage-wise, the majority of your acres, are you able to do these 10,000-foot laterals and, if so, is that the plan to continue to go certainly go after more of these?

Yes, the plan is to go after more. Our acreage position right now is very continuous and contiguous.

I think we averaged 9,500 feet roughly on our average laterals but to get to that average that means we will have plenty of them that will be above 10,000 feet as well as some that are in the 7,000 or 8,000 range. So, yes, we definitely will have a subset of our total that will be well above 10,000 feet.

Okay. Lastly, I guess the plan for the -- assume prices stay around the same area, I think you?ve got now the one Utica and seven Marcellus rigs. Given -- I'm just a bit surprised, any thoughts about either reallocating and going a little more aggressively in the Utica versus the Marcellus or just maybe if you could, why the one versus the seven given the economics?

Yes, we certainly like our Utica play very much and the well results but there is a certain circumstance that is important for people to know and that is, all we have on the recs westbound lateral, is 600 million cubic feet a day of firm transport and that lateral is running full. They filed for an expansion that's been approved but it won't become available until the middle of 2017.

Until that time we are capped out at 600 million a day and so that's pretty much where we are right now. The one rig in the Utica will keep us right there at 600 million a day.

The relief that we are expecting is energy transfers Rover pipeline and that will come to the Seneca area by mid-2017. When that comes we will have as much as 800 million a day of additional takeaway on Rover that ties to our Midwest and our Gulf markets. That is why we?ve reallocated capital over to the Marcellus side for the next year or 15 months is to ride that constraint.

Makes sense and then just lastly, you have already, certainly, have a big acres position. Any thoughts you might have on M&A deals you're seeing, any thoughts about how aggressively are you all looking at anything?

We certainly have as good a handle as anybody on ownerships throughout the trend. We have more than 300 lease brokers that have worked the courthouses and so we really know who is out there and we continue to add on a base leasing basis and also we buy selected acreage from such players as Magnum Hunter that we announced last year.

I think you will see selective transactions where we will buy acreage and slightly larger blocks and then continue to pick up our -- lease 500 acres a week through base leasing, filling in, and expanding.

Makes sense. Thank you.

And our next question come from Phillip Jungwirth of BMO Capital Markets.

Good morning. Kinder had commented on a mutual agreement to defer the inservice day for the Broadrun expansion project and was just hoping you could provide any color from Antero's view on the reasoning behind the deferral. As we look at your future FT portfolio, are there any other additions that could be deferred?

Yes, so that's right. Our TGP -- we?ll have the right to expand that from 590 million a day to 790 million a day so Kinder and Antero agreed that that would be put off until mid-2018. That is the plan.

There are other projects out there. We are not pushing for any delays.

The FT that we stepped into we will fill most of it by 2019. We will see how some of these things come about. There is no negotiation going on to -- for us trying to delay any projects.

Great and then you mentioned reducing your stake in the LP units of Antero Midstream, which was the first time since IPO. Two questions, one, how important is it to maintain over 50% ownership of the LP? Then two, if ownership were to drop below 50% would AM still be consolidated by Antero resources?

Yes. If ownership dropped below 50% we would continue to consolidate because it is a common affiliates. That is not a particular trigger point but we are very happy with our ownership there. We see lots of appreciation upside. This transaction was really meant to complete the transaction from last September when the market was tough.

It is still tough on MLP side in general but it was difficult then. We did a pie transaction for about half of the AM equity that we wanted to put away and this transaction took care of most of the other half of that transaction. That was really the plan there. As opposed to a methodical sell down of AM, that is not the plan right now.

Okay. Great. Antero certainly has a very valuable hedge book and I know the question has been asked about your willingness to unwind this. Specifically as it relates to 2017, where supply-demand fundamentals do seem to be improving, it looks like you are over 100% hedged at least on projected dry gas volumes. So curious as to your willingness to roll some of the 2017 hedges into later periods such as 2019, 2020, 2021, where you did add some hedges in the quarter.

That is a good question. We have virtually never unwound hedges. The track record of those who have materially unwound them has not been so great. We consider that our protection.

That is right. We have a lot of flexibility. If we are slightly over hedged in a certain year, well, as we get close and we look at our projections, the projections change from time to time, from year to year. So you never know whether by the time we get close to that year whether it will be over hedged or not.

You are right. We can also through spread trades move the hedges back and forth. And so move them to further out years. It is a pretty simple and pretty liquid market to move some of those volumes out to later years if we wanted to.

Great. Thanks.

And our next question comes from Brian Singer of Goldman Sachs.

Thank you. Good morning. I recognized you haven't made any official changes to your type curve, but can you talk to -- with the efficiencies that you are seeing and expectations for further efficiencies?

How, if at all, this would change your strategy regarding what price you would need to see to accelerate activity? What price at which you would want to sign new contracts for takeaway? I know in the very near-term we are talking about delays, but sign new long-term contracts for takeaway and how low a price longer-term you would feel comfortable hedging?

So in terms of type curves, I think we can say we are encouraged by our results over the last year and the improvements but we are pretty conservative. So it is going to take, with our reserve engineering group, probably a year anyway of many wells demonstrating an uptick before we would change the type curve.

But certainly better results means that one can develop at lower prices if we wanted to. We are not really looking to sign on for any more FT at this point. We have a number of projects that are coming on and we project that we will fill them in due course through calendar 2019.

We will be pretty full. I think rather than sign contracts with new projects, the new projects generally are quite a bit more expensive than the ones that we have now because they are new builds whereas a lot of ours were either reversals, first of all back hauls, then reversals where the molecules flow in a different direction, or compression projects.

That is why we have such low FT relative to new builds. So what would we do if we needed more capacity even to accelerate beyond what we have now? Odds are that there are a number of more distressed parties that have signed on to plenty of future projects that are in distress and probably won't be using their capacity.

It is always a first alternative would be to look at what is called release capacity, where you sublet their capacity and if they do it in a formal way, it is put out on a bulletin board and sometimes those are discounted pretty heavily. Sometimes it is a premium, but if pipes are under filled and we needed more, then we would look to be able to use somebody else's space at a discounted rate. That would probably be the first direction we would go.

Got it. And then the hedging side of things, if your breakeven is increasingly moving below $2 and I don't know whether that's how you think about it on a corporate level or a well level, do you start to have more comfort with a long-term gas price of $3 or lower and hedging at those levels?

Well, the way we look at hedging right now we are fortunate that we have such a substantial hedge position. So we are fully hedged in 2016 and 2017 and more than 80% hedged in 2018 and 2019.

So we feel very secure. We also have hedges out in the 2021 and 2022 area, but we have the luxury right now of just watching. And we have been watching for a while now for several months and have seen the curves moving up. We are not really looking to jump anytime soon at locking in more.

The lowest hedges we have put in place, in many years, have been in the $2.75 range. Is that an ideal price? No. If you asked us today, where do we think longer-term gas prices are going to be, somewhere in that $2.75 to $3.50 or even $3.75 range. We might be looking toward those.

I think we can develop at quite a bit lower prices than that but -- and withstand those but we are looking for higher prices and we are extremely well protected over the next four years. So I don't think you will see us going -- CAL 17 right now is hovering right at about $3 and I don't think anytime soon we will be going and hedging below that.

I think we are looking for higher prices yet and probably on the outer part of the curve. CAL 22 this morning $3.40 so you can see we are inching up to about $3.50 range. We will be looking towards the outer part of the curve, but not necessarily real soon.

Got it. I guess lastly, I think you mentioned early on or in one of your presentations the balance sheet doesn't get incrementally more leverage; potentially the opposite as you go about your growth strategy. Can you talk about interest levels beyond letting that play out in deleveraging particularly from material asset sales or equity at the parent level?

I think all we can say on that front is stable leverage this year and we expect to drive that down over time. The nice thing is we are in a very opportunistic position where we do not have to do anything right now.

We have a great hedge position, as Paul said, fully hedged, fully sold out essentially on our gas over the next two years, and most of our propane over the next two years, so we are good shape there. We can be optimistic and then I think you probably heard the guidance that over time we want to drive that down well under three times leverage.

Great. Thank you.

And our next question comes from James Sullivan, of Alembic Global Advisors.

Could you comment very quickly. We know you talked about it last quarter but on your evolving ethane NGL marketing strategy for incremental volumes. I know obviously you have got ATEX and Mariner East and so on. How do you see that market developing, number one?

Number two, I know it would have seemed like an out-there question six months ago, but has there been any talk on ATEX capacity expansion yet or do you think the appetite is greater for the nearer-in markets like Sarnia and so on?

Yes, so the ethane market certainly is improving. Why is that? Well, it is in part, people are foreseeing over the next couple of years the petro chem demand in the US as well as exports becoming a reality in the [arb] to places like Northwest Europe are positive so can see more and more interest in that.

I haven't heard any talk yet of ATEX expansion. It is still probably running 50% to 60% full. And so yes, maybe one would explore, if we were looking for more FT, would it be a Mariner East or more of ATEX but unexpanded or the local markets, as you say.

There?s still three cracker projects that are out there, ethane cracker projects in Appalachia that have not gone FID. Certainly, if things got healthier, then we would definitely look at those and pursue those a little bit more. We would be supportive of those so we would look locally. Yes, there has been a lot of positive dynamic.

If you look at gas value of ethane right now, it is in the mid- to high teens, whereas the futures market you are seeing 17 and 18 now in the $0.26 to $0.28 so, there is definitely a premium developing beyond gas value for ethane and so the market is definitely seeing shortages and more demand.

Great. Thanks for the color. Do you have any commentary -- I know we've already touched on it once today, but on the Rover timeline, I know it's been delayed and you are probably just working with the ET timeline which is mid-2017. Do you have any commentary on that or on the kind of chatter about it getting downsized, number one?

And then on the other hand, given your reservation on that, I know you talked about keeping the one rig running in Utica, just to fill recs until that starts up. Would you -- how long do you think you need to fill your capacity on there? I know that is a loosey-goosey question because capital is your constraint but -- or maybe said another way, how much would it cost to sell it and would you ramp ahead of time to try to absorb the capacity?

So, we do have discussions with Energy Transfer. They have been very good at updating us on their progress. We do believe their timetable of having Rover in place by mid-2017. There's some interesting photographs out there now of their staging yard in Massillon, Ohio and they have over 400 miles of 42-inch pipes that are there in the staging area, and that would build out in a large segment of Rover from Claring to Defiance plus a couple of legs.

I think they are going to phase it in, but I'm not sure what they have said, so not sure whether it is full-bore at 3 plus Bcf a day or something less than that. But we are certainly happy to get our FT on Rover.

We have 800 million a day contracted with them and the way our projections look right now, it will take on the order of a year to a year and a half for us to be able to fill that out of the Marcellus. There may be, as we gain more confidence, that that truly is the timetable.

We may begin to put rigs back to work in 2017, getting ready to ramp up into the new Rover capacity. It takes a while to, of course, drill out pads, and then frac them and get ready for production. Let's say, in early 2017, if we are convinced that it is coming in mid-2017, you could see us put more rigs back to work in the Utica.

Okay, guys. Thanks so much.

And our next question comes from Ben Wyatt, of Stephens.

Good morning, guys. A quick question on slide 10. You have some information here on rigs and crews.

And just curious if you could give us any color on how you see that shaking out maybe over the next couple of years, that ratio of rigs to crews? And then your thoughts around, if you were to ramp in 2017 and 2018, any tightness on the oilfield services side considering the downturn?

Of course, everyone is following the rig count and a whole lot of rigs have been laid down. The rigs that have been laid down in Appalachia are dry stacked in Appalachia, so they haven't left the region. But, definitely the crews have been downsized. It is probably easier to ramp things up and pull rigs out of stacking and those are more readily available than the crews.

We would expect as the industry begins to ramp back up that probably the most experienced crews would be called back first, so I don't think we would have to go through the cycle of very green hands like you see when there were 1,600-plus rigs running and the last crews were extremely green.

Probably could attract the experienced crews. We have not seen any pressure on oilfield services that still we're seeing. There's plenty of services being available on the spot rate, both on drilling rates for the kinds of rigs we like and the stage costs on -- with who we think are competent frac companies. But those have gone down quite a bit and don't any upward pressure at all.

Very good. Thank you.

And our next question is a follow-up from James Sullivan, of Alembic Global Advisors.

Thanks for letting me on one more time. Real quick, I just wanted to clarify, I think you had said this but in your maintenance and growth capital assumptions on slide 6 of the presentations, are you using your 2015 F&D per Mcfe numbers or are you using them for the Q1 2016 numbers which are the lower ones?

We are using ERN assumptions around reserves per well and the production that comes from those wells. There is an upside to those production forecasts if we continue to see 2 Bcfe per thousand or 2 Bcf per thousand at the well-head or greater over time, so you do see some production upside there with the same dollar spending.

Great. Thanks. And just last one here, on the 10,000-foot lateral slide -- and this may be me reading a little too much into your graphic, but it looks like there's a little bit more dispersion from the mean in the well results as you go out past 10,000 feet. Is that just noise or do you think it has anything to do with the relative difficulty of landing in zone when you go out that long and where does the risk reward become unattractive for the superb long laterals?

Well James, this is a new slide. I don't think we would attribute any greater range of outcomes, only that it's newer.

I think we have quite a bit of confidence that we can stay in zone for 10,000 feet. Just as we score proppant placement, we also score staying within zone and it is in the high 90s percent. I think we are in good shape there.

We are fortunate that we are in an area where there is virtually no folding or faulting. So it is readily defined and we get better all the time.

I see your point that that oval looks a little bit bigger. I'm not sure if you got rid of the oval where you can see much more dispersion. Maybe there's more dispersion, or difference to the upside. I see more points north of the curve than south, but it is a good question but we're not really seeing it that way. That it gets more risky going out that far.

All right. Great. Thanks very much.

And this concludes the question and answer session. I'd like to turn the conference back over to management for closing remarks.

Thank you for joining us on our conference call today. Please feel free to reach out to us if you have any further questions. Thanks again.

And thank you, sir. Today's conference has now concluded and we thank you all for attending today's presentation. You may disconnect and have a wonderful day.