Antero Resources Corp (AR) 2016 Q3 法說會逐字稿

Good day and welcome to the Antero Resources' third-quarter 2016 earnings conference call and webcast.

(Operator instructions)

I would now like to turn the conference over to Mr. Michael Kennedy, Senior Vice President of Finance. Please go ahead.

Thank you for joining us for Antero's third-quarter 2016 investor conference call. We 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 forecasted in such statements. Joining me on the call today are Paul Rady, Chairman and CEO; and Glenn Warren, President and CFO. I will now to the call over to Glen.

Thank you, Mike. Thank you to everyone for listening to the call today. In my comments I'm going to highlight our third-quarter financial results, including price realizations and EBITDAX margins, discuss the current firm transportation outlook in Appalachia and touch on our balance sheet and free cash flow.

Paul will then provide commentary on the operational efficiencies and improvement in recoveries that we continue to achieve and give an update on our continued consolidation in the basin. Let's begin with some of the key highlights from the quarter. Production averaged a record 1.875 Bcfe per day for the quarter, including over 81,000 barrels a day of liquids, representing 6% quarter-over-quarter growth. This production out performance continues to be driven by operational improvements, particularly the advanced completions that were implemented early this year, which Paul will discuss further in his remarks in a moment,

Moving on to realized pricing during the quarter, we realized $0.05 premium to the NYMEX Henry Hub on our gas production during the quarter despite Dominion South and TETCO-M2 differentials averaging $1.62 per MMBTU back of NYMEX Henry Hub. This is $0.77 per Mcf the higher than the next closest peer that has reported thus far and $1.53 above the blended TETCO Dom South index for the quarter, which truly highlights the value of our firm transport portfolio, an advantage we have over our peers, moving virtually all of our gas away from unfavorable local Appalachian indices. To further boil down our firm transport I will direct you to slide number 2 in the deck, titled Antero FIrm Transport Eliminates Northeast Basis Risk.

Looking out through 2020, the year 2020, and utilizing our firm transportation portfolio to sell our gas into favorable markets, we expect to generate a premium to NYMEX of approximately $0.10 per Mcf. After taking into account the firm transport costs of $0.46 per Mcf to our gas away from unfavorable indices, which goes to operating expenses by the way, plus the costs associated with unutilized firm transport of $0.10 per Mcf, you can see our true netback price is expected to average NYMEX less $0.46.

When you think about the alternative, if we were to sell our gas at local indices like Dominion South and TETCO, we would avoid the firm transport cost, however, we would average a netback based on September 30th strip pricing of NYMEX less $0.91, or $0.45 worse than what we expect to receive through utilizing our firm transport portfolio. I think it's also important to point out that the strip pricing I'm referring to indicates a relative tightening at local basis which has been priced in to give effect to the pipeline projects that are expected to come online. Given the current environment today as it relates to pipeline projects, I think many would agree there's significant risk that tightening of Dom South and TETCO basis may not occur at the levels applied by the current strip, which results in an even higher average index netback than $0.91.

Moving onto liquids pricing, we realized an unhedged C3+ NGL price of $17.56 per barrel or 39% of NYMEX WTI, an ethane price of $0.19 per gallon, or $8 per barrel in the Northeast. The C3+ NGL pricing of 39% of WTI during the quarter was at the high end of our 35% to 40% range of WTI full-year guidance, primarily driven by an improvement on the Mont Bellvieu to WTI relationship, along with local differentials coming in as expected.

Continuing on the liquids topic, let me briefly touch on our liquids exposure as we see more upside in liquids pricing relative to gas pricing over the next few years. To help try and break it down, I'll refer you to slide number 3, titled Significant Liquids Pricing Exposure. As you can see in the chart, for every approximate $5 per barrel move in oil prices, assuming the Mont Bellvieu NGL price to WTI ratio remains consistent with the current strip relationship, our upstream EBITDAX would improve by roughly 6%.

For example, at an average oil price of $70 a barrel through the end of the decade, our upstream EBITDAX would increase by 17% over the base case at strip, or roughly, a $1 billion to $1.5 billion. So any healthy leverage to oil prices for a Appalachian producer which provides us with nice diversity of cash flow from a commodity standpoint. I think it's also important to point out, as highlighted on slide 4, titled Largest Core Inventory In Appalachia, we are the largest holder of core acreage in Appalachia.

Over 587,000 net acres core position is only 15% developed and includes 4,300 undeveloped horizontal drilling locations. With 435,000 net acres we are also the largest holder of core liquids-rich acreage by factor of over two times our next closest peer. The key part of our strategy throughout this downturn has been to position ourselves for an NGL price recovery and we believe we are best positioned to capture this upside.

And as you can see on slide number 5, titled Improving Marcellus Well Economics, roughly 1,900 of our un-drilled locations are located in the 1,200 to 1325 BTU band in the Marcellus and are delivering half-cycle rates in the 50% to 78% range using current strip pricing before hedging. Moving to cash expenses, I wanted to touch briefly on net marketing expense, which decreased to $18 million or $0.10 per Mcfe during the quarter. The was a reduction was a function of releasing capacity on our ANR South segment to a third-party as well as increased spreads on marketed gas due to the widening of local indices.

During the quarter, we generated $373 million in consolidated EBITDAX, a company record. Details on slide number 6, titled Highest EBITDAX and Margins Among Peers. Our EBITDAX increased by 28% year over year and has far exceeded that of our peers for the last several quarters, as you can see. This chart is a bottom-line testament to our integrated business strategy which includes best rock, firm transport to favorable price indices, and forward sales of a significant portion of our gas at fixed prices. We like our position.

Moving on to the balance sheet and liquidity, I will refer you to slide number 7 now, titled Strong balance sheet and Liquidity. We announced yesterday that we have signed a definitive agreement to sell approximately 17,000 net acres, primarily located in Washington and West Moreland Counties, Pennsylvania, for $170 million. This was acreage outside of our five-year development plan and in an area that does not have Antero midstream gathering infrastructure in place today. We thought it was very prudent to bring that PV forward, particularly as we continue to consolidate acreage in West Virginia and Ohio for near-term development.

In addition to this divestiture, we also raised $175 million in early October through a private placement of 6.7 million shares to Temasek Holdings, a well-respected, sovereign wealth fund in Singapore. Furthermore, as part of the fall borrowing base redetermination, our borrowing base was increased by $250 million to $4.75 billion and that was without any increase in the commitments. So that remains at $4 billion.

The increase is a direct result of our growing core liquids-rich PUD drilling inventory and the significant PDP reserve growth. Year-to-date, we have added a total of 99 PDP wells. Pro forma for the $345 million in proceeds from the aforementioned transactions, our September 30th consolidated net debt to the latest 12 month EBITDAX was 3.2 times.

We have strong visibility that leverage will continue to trend down as we forecast increasing EBITDAX in 2017 and 2018, supported by our production growth of 20% to 25% per year. Hedges in place that cover all of our natural gas production in 2017 at $3.63 per MMBTU, and at $3.91 in 2018 and similar capital spending in those years to our 2016 spend. With that, I will turn over to Paul for his comments.

Thanks, Glen. In my comments today I will provide an update on our operational efficiencies, highlight the improve recoveries that we are achieving through the advanced completion techniques that we implemented earlier this year and touch on our continued efforts to consolidate the basin. Now, let me first discuss the operational efficiencies and cost reductions we continue to achieve today.

As you can see, on slide number 8, entitled, Proven Track Record of Well Cost Reductions, AR are has reduced its well cost by 36% in the Marcellus since 2014 to $0.86 million per thousand feet of lateral. The continued reduction in well cost is a result of both operational efficiencies through faster drilling and completions combined with long-term service contracts rolling off and being replaced with current market-priced services, despite the rising commodity price environment.

The bottom half of the slide illustrates that we've seen similar success in the Utica, with well costs totaling $1 million per thousand feet of lateral, representing a 35% decline since 2014. Additionally, current Marcellus and Utica well costs represent an 18% and 15% reduction, respectively, compared to well costs assumed in AR's year-end 2015 reserves. At this point, we have not seen any upward pressure on service costs.

In fact, on the drilling side, we have entered into long-term contracts at current market rates for several rigs through 2019. And on the completion side we have contracted for approximately 5,000 completion stages per year through 2018. Shifting gears to wellhead recoveries, we continue to achieve encouraging results utilizing advanced completion techniques we implemented earlier this year. To provide further clarity, I will direct you to slide number 9, entitled, Optimizing Well Recoveries From Advanced Completions.

As you can see, in the table at the top of the page, we've laid out the pertinent completion metrics and how the associated components have changed in the Marcellus since 2013. As outlined in the furthest column to the right, we have increased the profit used per foot of lateral by 64% and the water used per foot of lateral by 54% since 2013. The increased sand and water concentration has resulted in a 33% overall improvement in recoveries based on the results of our enhanced completions to date.

In the chart on this page, we've outlined three different cumulative production curves for the first two year period of a well's life. The green legacy curve represents the production curve from wells competed in 2013 when we were using only 900 pounds of proppant per foot and had not transitioned to shorter stage lengths, or SSLs.

The orange curve represents the type curve assumed for all of our Marcellus reserves today. This is supported by over 200 Marcellus wells placed online since we migrated to SSLs in late 2013. And finally, the yellow 2.0 Bcfe per thousand line represents the cumulative production curve we are currently estimating.

Based on results from the advanced completion wells outlined under the 2016 column in the table at the top. To date, we've completed 33 wells using advanced completion techniques, which we generally define as using more than 1,300 pounds per foot of lateral. The aggregated production from these wells is tracking the 2.0 Bcfe per thousand type curve.

This improvement in recoveries has really been a key driver behind the overall production and out performance we're seeing on a Company-wide basis this year. On a year-to-date basis, looking back at the Marcellus we have completed 69 wells and turned them to sales and they all have at least 90 days of production history. The 69 wells have an average EUR of 20.6 Bcf-equivalent at 1245 BTU gas and assuming ethane rejection, an average lateral length of 9,000 feet and an average all-in development costs of $0.53 per Mcfe.

Note, that the 20.6 Bcfe average EUR processed is actually 26 Bcfe per well in full ethane recovery. Also keep in mind, the development costs associated with these completions partially reflects legacy drilling and completion contract rates. As these legacy contracts continue to roll off and the operational efficiencies continue, we expect to further decline in development costs.

Antero has been a leader in long lateral since the inception of the Marcellus and Utica shale plays. The economic benefit of drilling these long laterals is illustrated on slide 10, entitled, Longer Laterals Improve Well Economics. Notice, the increase in economics from a 63% rate of return to a 78% rate of return when we go from the average peer company lateral of 6,500 feet to Antero's average of 9,000 feet.

Now, when you combine the reduction in well costs with long laterals and these optimized recoveries you really start to see a meaningful impact to the overall business creating significant value for shareholders. To try and summarize this point, I would like to refer you to slide 11, entitled, Capital Efficiency Driving Value To Shareholders. On the left-hand side of the page, we show the original 2016 production guidance that we issued back in February compared to the current 2016 production guidance, and the original 2017 production target compared to the current 2017 production target.

The right-hand side of the page, we show drilling and completion capital for the same time periods. The key takeaway from this page, is that we are now expecting to grow 2017 production approximately 150 million cubic feet equivalent a day higher than originally targeted while spending $225 million less capital to achieve this growth.

This results in more free cash flow available to spend in 2017 to drive 2018 production and cash flow. Let me finish up by discussing the continued consolidation we've achieved throughout the years and really since we've entered Appalachia in 2008. As you can see on slide number 12, entitled, Leading Consolidator In Appalachia, we've continuously consolidated core acreage in Appalachia since we entered the play in late 2008.

Since the end of 2014 alone, we've added over 85,000 net acres. We now have 629,000 net acres, including 587,000 acres within the core area and 85% of that is un-drilled acreage. This provides us with tremendous running room to develop high rate of return locations for many years ahead. We will continue to analyze opportunities for consolidation in the basin and believe that we are well positioned to capitalize on these opportunities.

In summary, we've made great strides operationally in 2016. Driving tremendous value for our shareholders. Our consolidation efforts have proved successful thus far and we see a number of exciting opportunities that lie ahead. Our business plan remains focused on driving down development cost, optimizing recoveries, achieving best in class realized pricing and pure leading margins and these will ultimately lead to value creation for our shareholders.

Looking ahead, we believe that we are uniquely positioned for long-term success. With that, operator, let's open it up for questions.

(Operator Instructions)

Neal Dingmann, of SunTrust.

Good morning, guys. Nice quarter. Say, first make sure I have this right. Do I recall, maybe just earlier this year you had a slight constraint of some Utica takeaway and today is that the case for any of your more active Utica areas?

Well, we had slight constraints through the quarter in Utica in July REX was down for maintenance some 10 days. But in the bigger picture we are constrained now that we're pretty well maxed out on our REX capacity at 600 million cubic feet a day. So we are drilling at a pace in the Utica to just maintain that 600 million cubic feet a day.

What is the next shoe to drop, the next event that we are looking forward to? It's Rover coming to the Utica play -- The Rover Project. And we estimate that it's scheduled to arrive, to be built to our Seneca outlet sometime between mid-2017 and the end of 2017. So that's what's constraining us and keeping us maxed.

We certainly have the alternative right there at Seneca to sell into TETCO. There's a tap there and plenty of capacity but obviously the TETCO price is so far behind, more than $1, $1 to $1.50 behind what we can sell netback-wise REX to Chicago and to REX Zone 3, that we would move the capital over to the Marcellus and are moving the resulting gas to better markets there.

So, just keeping it at 600 million [cubic feet] a day, waiting for the next project.

Got it. And, just one last follow-up, if takeaway was not really a concern, how do you think just in general terms about Marcellus growth and returns versus potential Utica.

I'm looking at those prior slides where you just show the single economics of the Marcellus and Utica. Is it just simply looking at it the pretax returns that you're looking at there? Or again, just how you think about the two primary areas?

Yes. We think of it -- I would say, when you look at our acreage and the size of the opportunities that Marcellus is probably three times as big, rough numbers 450,000 net-plus acres in Marcellus versus 150,000 [net acres] in the Utica.

So, the size of the opportunity is greater and capital is being spent kind of in proportion there. But yes, the Marcellus does have stronger economics at this point.

Very good. Thank you guys.

David Tameron, Wells Fargo.

When you talk about the longer laterals, if we think about the drilling program over the next two years, or even three years, how much of your development drilling will be on those longer laterals?

All of it will be on longer laterals. I think we're averaging 9,000 to 9,500 foot longer laterals. We gone out -- our longest laterals in the Utica are at 13,600 feet sideways and our longest now in the Marcellus are over 14,000 feet.

We're just completing our first 14,000 footer now, the Nova 2H, right in our central area. So, longer is better.

We don't necessarily have to go longer since we have good -- well-located paths and infrastructure to keep it in the 9,000 foot to 12,000 foot range but we are very comfortable going longer. So, I think you'll see us go longer as time goes on, which just improves the economics, obviously.

Okay. And then on the 1,500 number, have you tested higher? Do think it can take more sand? How should we think about -- its crept up the last few years, are you at what you view today as the optimal limit or do you think there is still upside to that number?

There's still upside. So what was once piloting at 1,500 pounds sand per foot on our advance completions, that's now our base case that everything is 1,500 pounds but we are piloting at 1,750 pounds and at 2,000 pounds right now.

And putting away the fracs no problem. So, we look forward to seeing what that will do and have expectations that it will improve further.

Okay. And then last one for me. NGL market -- or more importantly, infrastructure and takeaway. Can you just sum up, if you can, the way you view that in the Marcellus and Utica over the next couple of years.

Yes. So, we have reasonable markets in takeaway right now in the Marcellus. We are looking forward to a couple of projects coming in. We've talked about Mariners East II, which will open up things to the east for export out of Marcus Hook and we're an anchor shipper on that.

That's estimated to be in service in middle to end of next year. And so, that will open up things. We're recovering ethane right now and moving it either -- we're moving it through ATEX to markets that we have downstream of ATEX. So I think we see a positive environment going forward.

You can see that also in the futures prices for both ethane, propane, and butane that they are in Contango and as more infrastructure comes to the Northeast these -- not only the export markets. There's talk of another pipe that might go to Mont Belvieu out of our area then over the next five years the crackers come along and provide some local uptake, too, for the ethane. So generally, improving over the next number of years and overall, pricing is also improving.

Okay, thank you for the color and nice quarter.

Thank you.

Brian Singer of Goldman Sachs.

Thank you, good morning.

Good morning.

Following up on the topic of proppant per foot. Can you just talk to what you see as the limitations on this and, as you mentioned on David's question, you have had some strong results I think initially from the 1,750 pounds to 2000 pounds. What are the limitations on how high you can go and what do you expect to test next year?

Well, all we have designed and projected so far are the 1,750 pounds and 2,000 pounds. But, with positive encouragement I would guess that we will go up even higher certainly others in industry and other players are using more. And we haven't recognized the break-over point yet.

It's going to be a point of diminishing returns at some point, but we think mechanically we can put away the bigger fracs. So don't see a logistical or mechanical reason that we couldn't pump say 2,500 pounds. It works out, we've got the horsepower at the surface and friction reducers and so even on the long laterals we can break down the distance stages in a lateral; should be able to pump it away. We haven't needed to use gel, we are just using pure slick water without gels.

And we've adjusted the size of our proppant to be able to get the jobs away 100%. I don't think we've seen the limit yet. But we just are a little bit conservative on our piloting and just want to do each pilot where we will compare and contrast. We will, say, on a certain pad we will drill four wells to the north and complete them with 2,000 pounds, and four wells to the south at 1,500 pounds and compare results.

So we move a little bit slowly but just want to adjust one variable at a time. So, I do see it in our future that if the 2,000 pounds works, we will probably test higher.

Great. Thank you. And then, you brought up the topic of consolidation in your remarks, which you obviously made the acquisition here recently. Can you just give us a little bit of the lay of the land in West Virginia? And then, dry and wetter gas at Utica in Ohio? And where do you see the opportunities and how meaningful do you think that could be?

Yes. There are still opportunities and we're and all those discussions and I think you'll see further consolidation from the same guys who have been doing the consolidation thus far. I'm not sure they'll be of any greater magnitude, probably lesser.

But there are still opportunities to bolt on assets here and there. On the corporate side, you've seen a little bit of that but not a whole lot. And I don't think we expect to see a whole lot of that right away.

But, I think the asset consolidation will continue for some time in the core. We've been forthcoming about our core outlines and our advance completion or high-graded core. So I think that's where you're really seeing most of that consolidation activity, in Southwest Marcellus and some in the Utica, too. We will continue to be part of that I think as long as the prices are reasonable.

Great, thank you.

Thank you.

Carlos Newell, Raymond James.

Thanks for taking my call. With regard to the marketing business could you provide a bit of color on the third-party contractual agreement where you released some unutilized firm transportation?

Could you repeat that, Carlos? I couldn't quite hear all of that question.

No problem. If you could just provide a bit of color on the third-party contractual agreement mentioned in the press release, where you released some of the unutilized firm transportation and the associated cost with them?

Sure. So what we're talking about is our Rover capacity and so -- actually it's our energy transfer but it is our ANR capacity that's southbound out of REX Zone 3. So we signed up for ANR capacity and that began last year.

But, as Rover was proposed by Energy Transfer as part of our reward, I think for stepping forward and being an anchor shipper on Rover, Energy Transfer agreed to pick up the tariff on ANR South beginning last July 1st, until Rover is in operation. And so, that amounts to picking up a tariff of on the order of $70 million to $80 million a year.

Great. That's very helpful. And one other for me, what kind of increase in well costs should we expect from enhanced completions relative to model well costs currently being published?

Yes, the model well costs are really based on the 1,500 pounds per foot. And so as we escalate that to, let's say, towards 2,000 pounds, it's not a significant increase. It's in a couple hundred thousand dollar range, maybe $200,000 to $300,000 range, so it's not a real big increase at today's prices and costs.

That's fair. All right, thanks guys. That's it for me.

Thanks.

Dandruff be, Stifel.

Nice sale on the non-core acreage in Pennsylvania. Just curious if there's any other non-core positions your currently marketing? And if so, what are the size of those packages?

There is nothing contemplated at this point, we're not marketing anything else. That one made a lot of sense. It's core to the basin so we like the acreage and the buyer likes the acreage but it's a long way from our infrastructure.

And Antero's strategy from the very beginning has been to block up and build infrastructure, whether it is water or gathering compression around that block of acreage. So this one was a bit far afield and it made sense to part with that but almost everything else is pretty well blocked up in our position.

Great. Makes sense. And then productivity per foot is up nicely with completion optimizations in both the highly rich condensate and highly rich. I'm curious can you talk about potential for productivity uplifts in the dryer portions of the Marcellus? And then also have you tested or seen any productivity improvements in Utica?

Yes, first of all on the Marcellus, and I think we have in our Company presentation, we see others that, a little further north from our acreage, that have seen positive results from enhanced completions, bigger fracs, and we have a big outline on our map in our Company presentation on our website.

And, so do expect that it can work as well over on the east side of our acreage. We are going to test that later this year as well as into 2017. We have a number of DUCs that are quite well positioned to run pilots for the enhanced completions and so, that is being put into motion now for the fourth quarter, that we'll do enhanced completions on the docks on the east side. And if those work as we think, there's a very good chance they will, then that will extend that big loop that we have on our website to cover a fair amount of our Eastern acreage.

And then, in terms of the Utica, yes, we are ramping up there in terms of enhanced completions. We're doing some 2000-pound per foot testing over on that side as well. We adjust specific parameters. The Utica, we feel, needs a little less water per pound of sand and so on, but testing that as well, so it's -- in both plays, we're moving forward with bigger and bigger fracs.

Great. Thanks for all the color.

Our next question comes from Holly Stewart of Scotia Howard Weil. Please go ahead.

Good morning, gentlemen.

Good morning.

Hi, Holly.

Just maybe -- most of my questions have been answered, so maybe just sort of thinking about 2017, you've outlined your growth, you've kind of talked about the CapEx, running six rigs today. Where do you think you need to be, I guess, from a rig count perspective to get to those 2017 targets?

Holly, you know the efficiency gains have just been so tremendous. We were at 30 days to drill on the Marcellus -- a 9000-foot Marcellus a year ago, and today we're down into the 12-day, 14-day range. I've seen some even better than that. So, it's amazing what you can do with six rigs. So we really don't see much of an increase in the rig count next year. We'll probably run around six rigs next year, 6 1/2, let's say, to achieve those targets.

So we're in great shape net-wise, we don't need to add a lot of rigs. In fact, we've added a couple of longer term contracts just recently that term out through 2019, just to lock in day rates on the rig side. But we can get done what we need to get done with about six rigs next year. And of course, we do have the DUC inventory to complete, so that does keep the rig count down for the first part of next year, anyway.

Sure. Appreciate that. Any color on those rig contracts you'd care to share?

Well, we essentially termed them out at kind of market today's - market day rates. And so it's a nice fit in the portfolio for us, that could get us the drill versus well, the service companies to put away some of it, I think people are optimistic on the service side that prices are going to improve for day rates and all, over the next few years. But it's hard to say when that happens exactly, so, they were also happy to put it away in their portfolio under a long-term arrangement.

Yes. Perfect.

A little more color there. It might be relative to our legacy contracts. The day rate is about 60% or so of what they used to be.

Wow. Okay. Great. Thank you. And then I know we've sort of talked about, and maybe, Paul, you were referencing this on the last question, but just some dry gas opportunities that you guys were seeing. Any update there, just kind of on strategy, or maybe potential development?

We continue to see that the economics are a little better over on our rich gas side, so yes, we'll do some DUC completions and test out our enhanced completions, and just go from there. But I don't see that we're going to be shifting our rigs over to the east side in the Marcellus.

We are doing some dry gas drilling now in the Utica, and not way down depth, but just a mile or two miles from our rich fairway, slightly on the east side where those wells will not need processing, and we're using enhanced completion ideas there, as well. So, a little bit of dry gas going on in the Utica, and just to keep us topped off at that $600 million in a day and testing the DUCs on the east side of the Marcellus.

Got it. Great. Thanks, guys.

Thank you.

Our next question comes from James Sullivan of Alembic Global Advisers. Please go ahead.

Hey. Good morning, guys. Thanks for taking the questions.

Good morning.

Start quickly on with the northeast basin spreads, obviously continuing to widen out in October, can you guys just comment a little bit on where you guys -- where your marketing revenue is running in October and for Q4, what you think you're expecting versus Q3? Can you give any color on that?

Yes, so the gas that's constrained in Southwest PA, so those producers that are selling into TETCO M2 and Dominion South, that gas is at a huge differential to the TCO pool to Nymex. So there's quite a spread there. We're buying plenty of third-party gas. It's out on the order of at a minimum, up to $200 million a day, and on some days there are some constraints in the system that it can be 2 times to 2.5 times that. So good spread there, which leads of course to enhanced marketing revenue.

What you do see is that as it's constrained there, and the storage is full, that there are some constraints in the system. It's not as wide open. It's not perfectly wide open; otherwise we'd be filling our capacity with about a half a Bcf a day of third-party gas. So it bounces up and down from between $200 million and $500 million a day. But there's a good opportunity there and as the cold weather comes in and the storage constraints are removed, then we'll be able to buy more of that distressed gas.

We've also been buying quite a bit now on our Tennessee leg, that there are distressed producers all along that stretch from Broad Run. So our inlet for the Tennessee pipe in the vicinity of the TCO Pool that there's a lot of distressed gas between there and the Gulf. And so we're picking up a lot of volume, several hundred million cubic feet a day and picking up a pretty good spread. Yesterday's spread was $1 to $1.50 between what we could pick it up at and where we could drop it off at Columbia Gulf and Tennessee Gulf. So we continue to offset our unused capacity cost, and so it's going well.

Okay. Interesting. An interesting revenue story developing there. To go from kind of short-term to long-term then, you talked a little bit about ATEX and the ethane, and then NGL markets generally. But you have to pass in ATEX. What was your budget in upsizable pipe? What would your obligations and opportunity be on upsized capacity if the ethane market does develop in the way that we would obviously like to see it do over the next couple of years?

Yes, I'm not sure I heard all of that, but I think, at the end of the day, we've got 20,000 barrels a day of capacity on ATEX. And it's in the, kind of the mid, so you could call it $0.15 range or so a gallon. There is some additional capacity on ATEX that's available on a spot basis, but there's not a whole lot. There's probably, on a given day, 15,000 barrels to 20,000 barrels a day maybe of capacity on the ATEX.

So that's one outlet, but I think that Centennial -- or I'm sorry, Enterprise has talked about a new project, Centennial, just this week that would bring, say, another 100,000 barrels a day of ethane capacity. Mariner East II will also be able to move some, or Mariner East I. So we do see some more capacity breaking free here over the next couple of years.

Okay. Great. I was thinking about whether ATEX was upsizable, but maybe Centennial is in place of that. Last one from me.

It is. It is. ATEX is upsizable, but I think there's a debate going on as to which one of those ends up going.

Understood. Thank you. That's helpful. Just one really quick last one if I could squeeze in to you guys. You guys had talked about, obviously, you're constrained in the Utica until Rover starts up. You guys talked about a mid- to late 2017 time, so that obviously, it's not in your control, but you've obviously probably want to do some ramp activity for that. What is your confidence on that?

Obviously, you might work that into your 2017 plans. And I know you guys haven't done that yet, but how are you guys feeling about the likelihood of tie-in roughly on schedule with that?

Well, we're in touch with Energy Transfer and everything looks like it's going according to plan so far. But I think the next several months will be telling as to when they get their permit to build. The pipe is already laid out in the yard at Massillon, Ohio to build the leg from Clarington up to Defiance. So it's just a question of when they can put that into motion. So as we say, we risk it earliest is middle of 2017 and I wouldn't say latest is end of 2017, but some sort of risking there.

As we get better visibility on that, as in when they get their permit to build, then it's fewer variables and just how long will it take them to build it, to put it in the ground. Six to nine months is some estimates that we've seen. So I think we'll have better confidence by this year-end as to whether they've got the green light to go forward; and with that we can begin ramping and starting our drilling in the Utica. But we'll try and feather it in.

We also have the ability to move our gas around a little bit, and as Rover comes on, move our gas, switch it between Rover and REX, and for any unused capacity, let's say, on Rover as we ramp into it, we'll be able to buy distressed third-party gas and fill that unused capacity, or at least offset the cost. So our thought process are in place to ramp into Rover as it comes on sometime between mid-2017 and call it mid-2018.

Okay. Great. Thanks for the call, you guys. I really appreciate it.

Our next question comes from Ben Wyatt of Stephens. Please go ahead.

Yes, hey. Good morning, guys. Paul, maybe just going back to the well optimization slide, slide 9, focusing a lot on the profit per foot you guys are doing there. Just curious -- is this a good relationship that we're seeing, kind of the profit per foot to the barrels of water per foot? Meaning if, as you guys move to 2000 pounds of sand per - or profit per foot should we see a 50-barrel, 55-barrel per foot number on the water side, or is that not necessarily the case?

It's close. Directionally, it's the case, but it won't be directly proportional. If anything, it'll be a little bit less water, but proportionately close to the same.

Got it. That's helpful. And then, maybe just on the divestiture, you guys care to share private buyer, public, just any color around that?

Yes, I think it's a public buyer, and you can kind of triangulate with some of the other announcements made this week, I think, and see who bought that.

Yes. Yes. Very good. Appreciate it, guys. Nice quarter.

Thank you.

Our next question comes from Arun Jayaram of JPMorgan. Please go ahead.

Yes, good morning. My first question, with the AM now trading at an all-time high, I was just wondering about your thoughts around strategic ways to benefit the AR shareholder from AM.

Well, it's certainly a nice currency. Doing acquisitions is not really our game on the MLP side, but as we've said many times, we continue to look at downstream projects, and it's nice to have an attractive equity currency for that. For AR, there's no direct, specific plan to sell down any of those AM units. We certainly like the upside, even from here, with the growth that's built in and embedded over the next many, many years, so I think you'll see AR continue to hold most of that position.

That's helpful. Secondly, it sounds like there's no additional acreage that is kind of on the block, but nice transaction to monetize 17,000 acres for a nice upturn in terms of breakover value. As part of your broader inventory in acreage strategy, did you see further opportunities to divest, quote/unquote, maybe stuff that's just not going to be developed in the next 5 years to 10 years?

No, we don't. We like all of our acreage. Obviously, some is stronger than others but like it all, and so don't see ourselves calving any of that off to let go of it. Certainly, we have done lots of trades with the other peer companies in Appalachia and we'll continue to do that where it's mutually beneficial to block up. So there'll be some swapping back and forth, bigger pieces and smaller pieces, but nothing that we have that we'd say, don't like it and want to sell it.

Okay. And I may have just missed this because I dialed in just couple minutes late, but just can you remind me on where your DUCs are today and kind of the strategy and timing of normalizing those?

Yes, about 22 of the DUCs are further east and in that area of dedication, that's to a third party. The remaining DUCs are sort of between there and even scattered throughout our very rich Doddridge County acreage, and so when we talk about DUCs, just keep in mind that they're true DUCs. They're wells that have been taken out of the development cycle, they've been drilled and cased, but we're not moving onto them to complete and drill out.

So they truly are uncompleted wells that we've put on the shelf for the time being. We do plan to start getting back on some of those here in the fourth quarter. They won't be completed in the fourth quarter but we'll start to work on that DUC inventory. I'd say the BTU ranges from 1,150 Btu on the low end to as high as probably 1,250 Btu, 1,275 Btu on the high end, in terms of that DUC inventory.

And is that, the completion of DUCs you're going to start in the fourth quarter, is that already contemplated in your 2017 guide or could that provide some upside relative to that number?

It is because it's a long cycle, as you can imagine. All of our drilling is pad drilling now, I think that goes without saying, but we've got some pads now that have as many as 12 wells on them and we completed all 12 of those wells before we put them on line. So many, many pads have lots of wells. So even though we're going much faster with our stages per day, just getting on those pads and completing them, fracking the wells and then brining in the crew to drill out, add production equipment, all [that] takes some time.

So it's not going to impact the fourth quarter production in any material way. And it is factored in to our capital guidance for the year to be able to do that, do the savings that we've seen on well costs throughout the year.

Okay. Nice results. Thanks a lot.

Thank you.

Our next question comes from Marshall Carver of Heikkinen Energy Advisors. Please go ahead.

Yes. You mentioned the locking in of day rates at lower prices than the historical prices. Is that savings fully cooked in to the lower well costs in the presentation? Or is there another step down coming in well costs over the next quarter or two?

Yes. It's generally baked in the, sort of the market day rates.

All right. That's it from me. Thank you.

Thank you.

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

I'd like to thank everyone for joining us on our call today. Please feel free to reach out to us if you have any further questions. Thanks again. Bye, bye.

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