Antero Resources Corp (AR) 2016 Q2 法說會逐字稿

Good day and welcome to the Antero Resources' second-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 and Head of Investor Relations. Please go ahead, sir.

Thank you for joining us for Antero's second-quarter 2016 investor conference call. We'll spent a few minutes going through the financial and operational highlights, and then we'll open it up for Q&A. I'd also like to direct you to the homepage of our website at www.AnteroResources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call.

Before we start our comments, I would like to first remind you that during this call, Antero Management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control. Actual outcomes and results could materially differ from what is expressed, implied, or forecast in such statements.

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 Glen.

Thank you, Mike, and thank you to everyone for listening to our call today. In my comments, I'm going to highlight our second-quarter financial results, including price realizations and EBITDAX margins, touch on the attractive upside we see in an improving commodity price environment, and discuss the recent equity offering we completed during the quarter. Paul will then provide a brief update on the recently announced acreage acquisition in the core of the Marcellus, highlight the operational momentum we've maintained through the downturn, leading to significant drilling efficiencies and cost improvements, and provide additional color around improvement in recoveries that we are achieving. Let's begin with some of the key highlights from the quarter.

As we had another fantastic quarter, both operationally and financially, production averaged a record 1.762 Bcfe/d for the quarter, including over 75,000 barrels a day of liquids. This production record was achieved despite downtime at the Sherwood processing plant in West Virginia in late June, which resulted in 7.3 Bcfe of deferred production, averaging approximately 80 million cubic feet a day equivalent of production for the quarter.

The downtime was caused by an NGL pipeline slip that was repaired by the end of the quarter. The liquids production during the quarter included 17,000 barrels a day of ethane, which represented a 50% increase compared to the prior quarter, driven by an improvement in the ethane frac spread.

Moving on to realized pricing during the quarter, we realized an all-in price of $3.95 per Mcfe, including NGLs, oil, and hedges, despite the lowest average NYMEX natural gas price recorded for any quarter since 1999 at $1.95 per Mcf.

As you can see on slide 2 of our earnings call presentation titled 2Q 2016 Price Realizations of EBITDAX margin, we realized an average pre-hedge natural gas price of $1.93 per Mcf, and after hedge, price of $4.31 per Mcf. As you can see on the top half of the page, our pre-hedge gas price realization of $1.93 per Mcf was only $0.02 less than the average Nymex price and $0.35 higher than our next closest peer for the quarter. Our after-hedge gas price realization of $4.31 per Mcf was a $2.36 premium to the average Nymex price and $1.79 per Mcf higher than our next closest peer for the period, further demonstrating the significant value of our hedge book.

On a liquids front, we realized an unhedged C3-plus NGL price of $17.08 per barrel, or 38% of Nymex WTI, and an ethane price of $8.36 per barrel, or $0.20 per gallon. Directing you to the bottom half of the page, you can see how these superior price realizations and hedge gains translate into our peer-leading EBITDAX margin.

At $1.86 per Mcfe, our EBITDAX margin is $0.81 per Mcfe higher than the next closest peer. During the quarter, we generated $332 million in consolidated EBITDAX. As you can see on slide number 3, titled Highest EBITDAX and Margins among Peers, despite a decline in Nymex gas and oil prices of 26%, and 21% over the last year respectively, our EBITDAX increased by 24% year over year resulting in $100 million more cash flow than our next closest peer.

Detailed on the bottom half of the slide, this resulted in the fifth consecutive quarter in which Antero led the peer group in EBITDAX margins. The ability to consistently generate top-tier EBITDAX margins is a function of our differentiated strategy of targeting the best net-back pricing by moving our gas production outside of the basin with optimal takeaway, focusing on liquids-value uplift, and hedging our production often years in advance.

Antero's differentiated strategy offers investors in Appalachia a very stark choice; you can either invest in an active-core producer like AR, who has already sold over 80% of its forecast production through 2019 at $0.75 per Mcfe above the current-strip prices, or you can invest in producers who are partially hedged at lower prices, with lower activity levels, less core drilling inventory, and take your chances with prices and bases.

The next slide really quantifies this strategy. Directing you to slide number 4, titled Incremental Costs Drive Price Realizations. The blue outlined callout box demonstrates how our firm transportation expense of $0.40 per Mcfe enables us to sell our gas in an expected premium realization of $0.14 per Mcf compared to the strip pricing through 2018. Said another way, if you deducted the firm transport costs of $0.40 per Mcfe from our expected realized pricing, we would still achieve a net back of $2.83, which is $0.52 per Mcf higher than the Dominion South index that many of our peers are selling their gas at today. Many peers, of course, also sell at TETCO, which is very comparable pricing to Dominion South.

Now moving on to the liquids uptick. We pay approximately $0.60 per Mcfe in all-in processing fuel costs, y-grade transport, and fractionation costs and a $52 to $70 WTI range. This translates into $0.71 to $1.18 per Mcfe uplift in price realizations. While the base-cost structure may be higher than that of a dry-gas-focused producer, we see more upside on the liquids over the medium and longer term, and have positioned ourselves accordingly.

Directing you to the right half of the slide, AR would realize all-in pre-hedge prices of $4.18 to $4.41 per Mcfe, assuming $60 and $70 per barrel WTI prices respectively, and that's right on top of these dark green bars. While this strategy of drilling liquids-rich gas and locking in the most attractive takeaway in prices while incurring slightly higher costs may differ from many of our peers, the end result comes down to generating the highest margin per Mcfe to production, which we've consistently achieved and expect to continue moving forward.

So if you look at that cash margin, it's about $2, the difference between the total cash costs and that pre-hedge, all-and price. And you get that for spending about $0.50 on the F&D side, so a 4-to-1 ratio.

Before moving on to discuss our upside in an improving commodity price environment, I wanted to touch briefly on net-marketing expenses. During the quarter, we generated $91 million in net-marketing revenue and $126 million of marketing expenses. We've purchased and sold approximately 500 million cubic feet a day of third-party gas, utilizing excess capacity on the Tennessee gas pipeline, and capturing an average spread of $0.40 per Mcf. Net-marketing expense was ahead of internal expectations of $35 million, or $0.22 per Mcfe.

Looking forward to the remainder of the year, we are guiding to second-half 2016 net-marketing expenses of $0.10 to $0.15 per Mcfe. This significant reduction per Mcfe compared to the current quarterly results and a function of a previously announced third-party agreement that went into effect on July 1, 2016 and will continue until the Rover pipeline is placed in service or December 31, 2018, whichever is later. The third party has assumed responsibility for our stranded ANR Pipeline capacity and will pay the demand fees associated with that pipeline.

Now moving on to our [persisting] in a commodity-price rebound, particularly on the liquids pricing, I will direct you to slide number 5, entitled Largest Core Liquids Rich Drilling Inventory. In the yellow highlighted box, you will notice that pro forma for the pending acreage acquisition, we control an estimated 39% of the NGL reserves in the liquids-rich core of the Marcellus and Utica combined, which translates to about 420,000 net core liquids-rich acres. In fact, we're currently running 58% of the rigs in the liquids-rich core areas in all of Appalachia. A key part of our strategy is positioning ourselves for an NGL price recovery and we believe we're best position to capture this upside.

Now looking at slide number 6, titled NGL Growth and Ethane Optionality, we have guided to 47% NGL production growth in 2016, which is on top of our 117,000% growth in NGL production in 2015. Through the first two quarters of the year, we are well on track to hit this guidance. The NGL production growth guidance assumes a net 10,000 barrels a day of ethane, but we have substantial ethane optionality as well. Assuming a full ethane recovery scenario today, we would be producing over 90,000 net barrels per day of ethane, which gives you a feel for our ethane optionality.

Before I turn it over to Paul, I'll briefly touch on the equity offering that we completed in June to fund the recently announced pending acreage acquisition and reduce debt. On the base offering, we sold 26.8 million shares of common stock for net proceeds of $753 million. Just recently, we also closed on 3 million additional shares as part of the over-allotment option, generating an incremental $85 million.

The combined $838 million of net proceeds will be used to fund the acreage acquisition and for repayment of borrowings under our revolver, at least initially. The overall transaction was very well received due to the high-quality nature of the acreage, as we priced at the tightest spread for any E&P offering over $500 million since the commodity price downturn began in late 2014.

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

Thanks, Glen. In my comments today, I will discuss the significant benefits of maintaining operational momentum through this downturn, provide a brief update on the recent Marcellus core acreage acquisition, and finish with a review of our current well economics, which have improved tremendously through continued reductions in drilling costs, efficiencies, higher EURs, and improved commodity pricing.

As we've mentioned in the past, because of our strong hedge and firm-transport book, we've been in unique position to be able to maintain a significant level of development activity throughout this commodity price downturn. This has enabled us to continue moving up the learning curve as it relates to drilling efficiencies and overall well recoveries. While we cannot predict the future of commodity prices, we can say with conviction that we are operationally a stronger Company today than we were before the downturn.

As I'll touch on in more detail in my remarks, we have reduced well costs by over 30% over the last 18 months, and have increased overall recoveries by 20% or more over that same timeframe. Additionally, our strong balance sheet and financial position throughout the downturn has enabled us to consolidate core acreage and continue to high grade an attractive inventory of highly economic locations. Lastly, as we continued through this commodity price uncertainty, I'll remind you that we are 100% hedged on expected gas and propane production for the remainder of 2016 and 100% hedged on expected gas production in 2017 at prices that are more than $0.60 higher per Mcfe than the current strip pricing.

Now let me first provide you with an update of our pending core acreage acquisition and strategic rationale. I'll direct you to slide number 7, entitled Acquisition Update. As outlined on the top of the page, the tag-along rights on the acquisition have been exercised, adding an incremental 11,500 net acres and approximately 900 Bcf equivalent of unaudited Marcellus 3P reserves to the transaction. That brings the total acquired net acreage to 66,500 net acres, the total 3P reserves to 5.0 Tcf equivalent, and total net production of 16 million cubic feet equivalent per day, all for a purchase price of $546 million.

Overall, this acquisition will impact 1,060 gross undeveloped locations through either newly added locations, lateral extensions, or increased working interests on existing and future wells. What makes this acquisition even more exciting to Antero, among the other aspects listed on the slide, is the attractive liquids-rich well economics associated with the acreage that's consistent with recent Antero well results. With the application of our recent advanced completion techniques, we expect the acquired high-graded core acreage to yield similar consistent results.

Pro forma for the announced acquisition, we estimate that we control over 50% of the southern rich gas core, which is outlined in red on the map. This speaks to the substantial liquids-rich footprint we continue to build in the Southwest Marcellus to drive long-term value creation for our shareholders. Now let's move on to the operational efficiencies and cost reductions that we've achieved over the last 18 months.

On slide number 8, entitled Proven Track Record of Well Cost Reductions, AR has reduced its well cost by 34% in the Marcellus over the last 18 months to $0.9 million per 1,000 feet of lateral. The bottom half of the slide illustrates that we've seen similar success in the Utica, with well costs totaling $1 million per 1,000 feet of lateral, or a 33% decline over the last 18 months.

Not only did second-quarter 2016 well costs represent significant reductions compared to 2014, but 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 costs has been a function of reduced service costs, but more importantly, sustainable operational efficiencies. From a service-cost perspective, we are really in the driver's seat in terms of sustaining the cost reductions, a direct result of being the most active operator with seven rigs and five completion crews running.

To further touch on the operational efficiencies, I'll refer you to slide number 9, entitled Continuous Operating Improvement. During the quarter, we set another Company record, drilling 7,274 feet of lateral in a 24-hour period, while staying within a 10-foot zone.

The more efficient drilling led to a reduction in spud-to-rig-release drilling days in both the Marcellus and the Utica. In the Marcellus, drilling days have decreased by 48%, from 29 days in 2014 to 15 days during the second quarter. In the Utica, drilling days have decreased by 45% from 29 days in 2014 to 16 days in the second quarter.

Additionally, stages completed per day in the Marcellus increase by 22%, from 3.2 stages per day in 2014 to 3.9 stages per day during the second quarter. In the Utica, stages completed per day increased from 3.2 stages per day in 2014 to 4.4 stages per day in the second quarter, a 38% increase.

From a wellhead recovery standpoint, we continued to achieve encouraging results, utilizing advanced completion techniques. To provide further clarity, I'll direct you to slide number 10, entitled Advanced Completions Drive Higher EURs.

As you can see on this slide, we've normalized the 24 wells that have been placed on sales in 2016 and completed with at least 1,300 pounds of proppant per foot to times 0, so we've equalized all these wells to times 0, and those that have had at least a 9,000-foot lateral. We also included the 1.7 Bcfe per 1,000-foot type curve used for reserved booking at year-end 2015, and a 2.0 Bcf per 1,000-foot type curve as well.

The aggregated red production line is thus far exceeding the 2.0 Bcf per 1,000-type curve, which would represent a 33% increase compared to 2014 and an 18% increase relative to our 1.7 Bcf per 1,000- type curve. While we are still early in the evaluation process, the results are very encouraging.

As it relates to well economics, as you'd expect, a 33% reduction in well costs and a 33% increase in EURs has a significant impact on returns and drives very attractive economics on AR's developer program. To provide more color on this, I'll direct you to slide number 11, entitled Marcellus Upside Potential.

On this slide, we've provided rates of return in the highly-rich gas/condensate and highly rich-gas regimes of the Marcellus. These regimes represent the areas where we are active today and completing wells with the advanced completion techniques I just discussed. As detailed on the slide, if we are able to consistently develop to deliver the EURs to 2.0 Bcf wellhead gas per 1,000 feet of lateral, this translate into rates of return of 77% in the highly-rich gas/condensate areas and 51% in the highly-rich gas area, assuming June 30, 2016 strip pricing.

While still very early stage, we have begun pilot testing even higher profit loads with sand volumes upwards of 1,750 to 2,000 pounds per foot, and water volumes of 40 to 45 barrels per foot. We believe these higher profit loads have the potential for recoveries of upwards of 2.3 Bcf per 1,000, which would result in pretax rates of return of almost 100% in the highly-rich gas/condensate regime, and 66% in the highly-rich gas regime.

As a reminder, we have almost 2,000 locations in these two areas alone, pro forma for the announced acreage acquisition. This provides us with tremendous confidence that we can generate substantial value creation for many years to come.

In summary, we've made some of the biggest strides operationally in 2016 since we entered the play in 2008, and have further consolidated the liquids area of the Marcellus. Our business plan, which is focused on low unit-cost development, best-in-class realized pricing, peer-leading margins, and ongoing consolidation, continues to pay dividends for Antero.

Looking ahead, Antero is uniquely positioned for long-term success and will continue to thrive as commodity prices recover. In short, the outlook remains extremely bright for Antero.

With that, operator, let's open it up for questions.

We will now begin the question-and-answer session.

(Operator Instructions)

Brian Singer, Goldman Sachs.

To the point you made in your comments, natural gas prices are not necessarily the driver giving your hedges in FT. So you can you tell us your thoughts based on the extent of your willingness to outspend cash flow and how aggressively you see yourself -- or and how aggressively you want to have your balance sheet, where do you see investments moving as we going to 2017? And how we should think about that willingness to outspend cash flow?

Well, Brian this is Glen. Our balance sheet, we expect it to stay in the mid 3[%]s over the next -- in terms of leverage, over the next 12 to 18 months, and then decline over time back into the high 2[%]s just naturally. So it's levers that we're very comfortable with.

And in terms of ours D&C capital, for instance, for next year, we expect it to be pretty much in line with this year, which this year is $1.3 billion. So it should be in that same neighborhood next year in terms of capital spend for drilling and completions.

Got it. Great. And then two other small questions. The first is can you talk to the success that you're having or update us on the success that you're having in offloading any excess, the FT, and how that might be being shared with the other party? And then your thoughts on beyond the FT-specific portion you addressed in your comments, how the timing of the Rover pipeline would impact your production trajectory.

Yes. So in terms of Rover we projected -- we've, of course, had plenty of discussions with Energy Transfer. They just announced the other day that they received the final EIS to build Rover, so now there's a waiting period of approximately 90 days, and then construction could potentially begin later this year.

Handicapping as construction is going to take somewhere between 8 and 12 months, we see Rover being in operation sometime between mid 2017 and the end of 2017. And so with that, we'll adjust our budget as we get further clarity on that as to how much Utica versus Marcellus we'll develop.

We have currently maxed out our REX capacity at 600 million a day in the Utica, and so that's why we've toned it down for the next eight months or so and moved more of our capital back to the Marcellus. So Rover timing will have some effect on where we put the capital. But as we just detailed, we have excellent economics, rates of return, and so on in both plays, so it's great that we have the flexibility to move the capital back and forth.

In terms of the FT and offloading it, yes, we've been able to, as part of our agreement with Energy Transfer, they take on our southbound ANR until Rover is in service or the end of 2018, whichever is first. So that is 600,000 MMBtu a day, so that's important for us and helps in our reduction of net marketing expenses.

Beyond that, as Glen detailed, we've been buying third-party gas on the order of 500 million cubic feet a day, and we're sharing the margin with those producers. And we see that to continue going forward and that helps offset that marketing expense. Those are some of the bigger ones that we're definitely looking at other opportunities to offset marketing expense across our portfolio.

Great. Thanks very much.

Holly Stewart of Scotia Howard Weil.

My first question just on the acquisition, help us think through how that activity on those new properties gets worked in over the next few years.

Well, we could divide the acquisition into two parts: the part that where the acreage is in and amongst our existing acreage and in and amongst our existing infrastructure, gathering processing compression. That will be developed almost immediately over the next 18 months. We have rigs that will include a lot of that acreage within our units, or they are nearby units where we'll just move the rig over.

And then where it's a little further afield where it's in Wetzel County, it's going to take some time, at least 18 months, to begin building our infrastructure to be able to reach that far north. So it'll be phased in over the next year-and-a-half, two years for the more outlying acreage.

Okay, great. And then maybe, Glen, on the ethane volumes, just big ethane volumes really in the second quarter. No change to the guidance that would imply some material changes in the back half of the year. So is there something we should be thinking about with maybe that occurred in the second quarter or just how we should be thinking about the second half of the year for ethane.

No. I don't think so. We did not change the guidance, no, but I think you can expect us to exceed that guidance throughout the year. So the number for the second quarter would not be an unusual number. I think for the rest of the year, we just didn't change the guidance there, Holly. So I would not expect a significant pullback in ethane volumes.

Okay, great. And then one final one for me, if I could. On slide 10, you're showing with the advanced completions you're really outperforming the type curve. I know it's still early, but any thoughts on when you might be updating those curves?

Well, certainly, on updating the curves and our expectations, we get greater confidence, of course, with every well, with every pad. And that will lift our expectations. But as to how we would do -- lift the reserve bookings more area-wide, we're pretty conservative there. And so one needs quite a bit of production history, probably a year or more, to gain confidence, and then it'll begin just with direct and diagonal offset-type of reserve booking.

What we have done, once you have a statistical sampling that covers a much broader area, then we, with the reserve auditors, can book many of the locations in between. So it can be a larger uptick, but that's probably a year, year and half out to upsize the bookings in broad areas. It's going to be on a pad-by-pad basis for probably the next year.

I think just to add to that, reserve bookings are one topic certainly, but the other is I think you can assume that our expectation in that red outline that you see on our maps now is to see 2 Bcf per 1,000. That's certainly the target and the expectation going forward, and hopefully, it's even better than that, as we've said.

Got it. Thanks.

Thank you.

Neal Dingmann, SunTrust.

Say, maybe quickly for Glen first or maybe for you Paul, just on the outspend, again, obviously, it's translated very quickly into production and future upside. How comfortable are you with when you look into 2017 and exiting that year forward on the outspend?

Given our rates of return and the fact that leverage is expected to actually decline through the rest of the decade, we're quite comfortable out-spending as long as we continue to see stability in natural gas prices, and hopefully, some recovery again in oil and NGL prices. So the longer-range plan is to outspend over the next few years, given the kind of rates of return that we're looking at.

And we haven't really modeled in ourselves hitting 2 Bcf per 1,000 or higher in the Marcellus. So I think if we can consistently do that, then the outspend actually shrinks even further. So time will tell.

No. That certainly makes sense, and then just two others, if I could. Paul, you mentioned on those new properties that you all are building out, some pipe there. Is that -- what's the timing there and how much do you need to build out? I'm just wondering when you look at Wetzel and Tyler and Doddridge, to me, it's quite prospective obviously for both the Utica and Marcellus. But is that just going to be mostly infrastructure-dependent here in the next several quarters?

We're quite well built out already in Doddridge and pretty well built out in Tyler, so it's really Wetzel that is more far afield. So a lot of the infrastructure is already underway for Doddridge and Tyler, and we'll all be able to fold that in pretty quickly.

But it is Wetzel, and as we were saying, it's probably a year-and-a-half to reach the northern part, maybe two years to reach northern Wetzel, and it'll be a phased-in. We'll build the southern Wetzel first and be developing that, and then make the jump across. So it's going to take some time to get up to northern Wetzel.

Will that be mostly Utica-focused, Paul?

No, it will be mostly Marcellus-focused.

Okay, that's what I thought. And then just lastly, you have had, obviously, great -- just we're seeing -- can you push the profit -- seems to be more and more just pushing the economics on these wells. How do you see going forward? Will you continue to push the profit loading on a lot of these wells?

We will. We've got the pilots we mentioned of 1,750 and 2,000 pounds, and corresponding water volumes, and we'll see how those work out. We don't want to juggle too many parameters at once, too many variables. But yes, we'll test 1,750 and 2,000 and see if that gives us another good bump. And so right now, I think our standard design is going to be 1,500 with the piloting to go up to at least 2,000. We'll probably step beyond that, as well, over time.

Very good. Thank you all.

Thank you.

James Sullivan, Alembic Global Advisors.

Just very quick, obviously, you highlighted some great deliverability potential on the ethane side. Obviously looking at the spot market right now just back under $0.17 a gallon; that's despite the Morgan's Point start-up. Do you have any sense or can you comment a little bit just on how you see that market evolving over the next 12 or 18 months? I know that the start up at Morgan's Point is supposed to be pretty slow; they're not going to really hit capacity till late 2017. But there was a lot of line-fill with Mariner and doesn't seem to be much at Morgan's Point. Could you just give us your feel on that?

Well, I think we're optimistic longer term. We all probably read the same reports on the petrochems, the ethane crackers that are being built along the Gulf, and the added demand there, call it 400,000 or 500,000 barrels a day over the next one to two years. So that's going to help. As you mentioned, Morgan's Point, and certainly, we've talked with some of the ethane buyers that are shipping out of Morgan's Point to sell directly.

So I think it will improve, but it's going to be -- it's still under stress. At $0.17 you're right on the margin of whether you want to recover or leave it in the stream, and in fact, you probably disregard, if not for some costs, you'd definitely be leaving it in the stream.

Okay, great. Thanks for that.

Just shifting over then, if I look at just something on the Utica drilling side, if I look at your slide 8 from your presentation, you driven obviously phenomenal D&C cost-reductions. But if I just look at it, it looks like if the Utica drilling costs of the four elements, drilling completion between the two basins that have come down the least.

Now, on the other hand, your drilling days have come down on an order of magnitude, same magnitude as the Marcellus, 45% versus 48%, I think. Is there another factor that would account for the absolute dollar cost coming down a bit less in the Utica, and I'm thinking here maybe depth or legacy rig costs? And if it is the latter, legacy rig costs, do you know -- is there a time when that's supposed to roll off and you might get better re-contracted rates?

Yes, there are some legacy costs in there, but our rigs are rolling off in the next 6 to 18 months, and so that will help. But we just, we haven't had as much, I guess you call it, practice at the Utica, we haven't drilled as many wells. So a lot of the great efficiencies, the great operating techniques that we're working out in the Marcellus we just haven't done enough of those yet in the Utica.

So do expect that costs can come down further in the Utica, but we just haven't been as active there. As we say, fewer rigs drilling there and less capital planned until Rover goes into service, which is a year to a year-and-a-half away, so it'll be a little bit more subdued in our experimentation.

Okay, great. Something to look forward to then. Thanks. Appreciate it.

Thank you.

John Wolff, Jefferies.

Curious how Stonewall, as the volume transitioned from sending gas north versus going towards TICOs or how much volumes were reallocated. And then if you had any thoughts on why M2 Tetco point, Dominion South Point is still so weak, given that some volumes have been diverted and production in the basin has fallen.

Yes. So let me tackle the second one first. Tetco M2 and Dominion South continue to stand out when you look at indices really across the country. It's really Pennsylvania, Southwest PA, and Northeast PA that are in distress, whether it's Leidy]hub or Tetco M3 is Eastern PA. And so there's a lot of gas trying to escape, and just not enough straws in the pot in that area. That's a reason why we can buy distressed third-party gas and move it down our TICO capacity.

But I think there's just a lot of gas that's trying to move out of the Northeast Marcellus, so it comes around the horn. It comes from Northeast PA and comes down and tries to get out of Eastern PA. The markets are also distressed there.

So possibly some gas that was behind pipe but came on when you might've diverted, I think, several hundred million that were going north towards that direction?

Yes, that's true. So and that gets to your second question. It was several hundred million that we were sending before Stonewall opened, which was last November. Before that we were moving gas up EQT and Momentum to Tetco and selling into that distressed market. And you can see today's price TICO is very close to Nymex. It's maybe $0.13 off, whereas Tetco -- and so that would be in the [$2.60 -ish, $2.70] range, whereas Tetco M2 and down south are $1.35 to $1.40. So it makes a big difference and obviously -- so the big picture --

How may volumes do you think Stonewall were able to provide you to TICO with that expansion?

Well. We're moving --

Incrementally.

Were moving (inaudible) Bcf a day right now, and so it's going either to the TICO pool or the TICO base sales contract. So a lot of it, at least 300 million plus a day that was going to Tetco a few quarters ago is coming into the TICO pricing.

Got it, that's what I was looking for. And on -- you didn't talk -- I don't think he talked about the REX reversal, which I think is still scheduled for -- towards year end or early next year.

Yes, that's right.

Do you feel good about that, and does that help -- because I remember in the last call you said to expect Marcellus to be the driver of growth and Utica to be fairly flat. And does the Rex reversal, if it comes on in time, does that change that math? Or does that allow Utica to grow a little more?

Well, there's another complication there. So the Rex reversal, Rex right now is westbound is 1.8 Bcf a day, and they've just done a short shutdown to get prepared for the increase of another 800 million a day. And that's expected to come on in either the fourth quarter of the first quarter of next year. And so there will be westbound capacity out of Clarington, for example, and so that's going to help to, quote-unquote, drain the pool of Southwest PA and Eastern Ohio.

But the complication for Antero is we have our Seneca processing plant and the residue gas, of course, comes out of there, but if flows on the Seneca lateral, which is also maxed out at 600 Bcf million a day. So really, we don't see relief until Rover comes to the Seneca plant.

So others will be able to take advantage of Rex westbound once the new capacity is added, but we will still be constrained because we can't get up to and into the Rex lateral or into the Rex pipeline. So that won't make a difference for us.

That makes sense. Last one was on the -- I noticed in the last release that you had some success in laying off some third-party -- some FT third parties. Was that was that the case and is that an ongoing process for maybe the FT that's less preferreds, in your mind?

Well there's both. And so, the FT that we have remaining, especially in and around the TICO pool area and south to the Gulf, the east side of our FT, that's where we are making good returns on buying the distressed third-party gas from Southwest PA and moving it through either to the TICO pool or to the Gulf and offsetting FT costs and making a margin on that. So that's -- we haven't let go of that and that's good and that's desirable.

And then as I mentioned, a big amount is the FT that under the pre-negotiated agreement with Energy Transfer, which we've had for at least a year-and-a-half, as we signed up for Rover, it was the agreement that they'd take over AR southbound until -- beginning July 1. So last month July 1, 2016 until Rover is in service, which is, that's a big factor in reduction of FT costs.

Understood. Certainly helpful. Thanks.

Thank you.

David Deckelbaum, KeyBanc.

Thanks for taking my questions. Just curious, a follow-up on the M&A. You had successful bolt-ons, and you've pointed out that you now control a majority of that Southwest Marcellus core area. You also talked about the build out required in Wetzel.

In terms of the opportunity there, how much more opportunity is there to fold in acreage or pick up acreage that's already set along your midstream facilities there? And is there a strong desire to pursue things like that now, or getting back to your early conversations of comfortable growing production, you had the large hedge book, out-spending cash flow, keeping the balance sheet clean. And if you're able to pull off similar deals like the one that we just saw, should we expect you to pursue those pretty aggressively this year?

Well, there is the base load lacing that there's a continuing effort, and so the acres that we are acquiring in this pending acquisition, it's not completely blocked up. So there is an effort to continue to block it up, so that's one aspect. And then yes, we are continuing to monitor and engage around additional consolidation. And time will tell as to whether or not more of that gets done in a material fashion or not. It's just hard to say.

But we do still have an appetite for that. And while we're not ramping up the rig count dramatically, with -- as Paul mentioned earlier, and we're taking a modern approach to this and adding one rig driven by that southwestern acquisition here next year.

I think you can assume over time as we expand the platform with a larger and larger resource base, then activity is going to expand commensurate with that. We're not looking to just add more locations to extend the life of the drilling program. It's really more about building a bigger company and building it more rapidly but keeping leveraged in check.

So there are lots of factors that you take into consideration when you're negotiating these deals, but there still are some attractive opportunities out there.

That's helpful.

And then the last one for me, and maybe it's a little bit of an oddball question, but suppose that we go into the end of the year here and we do see supply declines persisting, demand pickup on the gas side. You see Henry Hub pricing spiking above where your hedge book is in 2017, you're 10% hedged. In that framework, does that just become as we get closer to where your hedge book is, is that just the trigger to increase production further? Or how do you think about capturing potential near-term spikes in the market that might persist for 12 months or so?

Yes, I think that's a good way to think about it. It'll be a measured approach but if we were to see sustained $4 gas, then that would certainly -- and maybe even below that, stimulate more drilling beyond what we've talked about is our D&C budget similar to this year. We can certainly increase that fairly easily, have lots and lots of inventory to drill, so that's an opportunity.

Thanks.

Thank you.

Drew Venker, Morgan Stanley.

I just wanted to ask a couple questions about the longer-term planning. You guys have been drilling longer laterals than a lot of your peers for quite some time now in Appalachia. And we've seen some industry test that are actually much, much longer, close to 20,000 feet drilled successfully. Do you feel like that is something that's technically feasible for you or that would be practical to implement on a widespread basis, given physical limitations or acreage, lease geometry, things like that?

That's a good question. The longest we've drilled so far is out to 14,000 feet sideways, and we did that pretty trouble-free. We know of the wells over in the Utica that have gone out towards that 20,000 feet. The good news for us is we don't have the acreage limitations where we need to go to 20,000 feet if something is unreachable.

So would that be a money-saver versus a concentration problem? I think you would say that if you go extra long like that, we haven't junked any well bores in a long time, but if something went wrong on the mechanical side, is that higher risk?

So we are going longer and longer. We're in the mid-9,000 feet these days as an average lateral, 9,000-plus feet. We feel quite comfortable and have a lot of the schedule that are in the 11,000 feet to 14,000 range feet, and we'll just see. We haven't completed our 14,000 footer yet. Expect it to not be a problem, but the theoretical limitation could be can you break down the very furthest stages out at the toe of the wellbore? Do you have enough horsepower to overcome friction loss and get into those far zones?

And so we think we can. We've got the numbers that say we can, but we'll want to do that before we start thinking about the 20,000 footer or the 18,000 foot. But as I say, the good news is we can reach about everything we have with shorter laterals than that. So it would have to be a good cost savings to balance the higher risk.

Okay, so Paul, it sounds like it would be more of a somewhat aggressive, but somewhat measured approach to pushing those out longer than just some rapid jump to 20,000 feet.

Yes.

And then on the higher profit loading and the better performance you've see, I just want to make sure I understood the answer to that question earlier on the call. If we continue to see similar performance in those higher profit loadings, would you spend that additional cash flow, or let that cash flow accrue to the balance sheet?

Yes, so that might've been -- I think Glen might've answered that one.

I think that's really just a function of well economics, right, if it makes sense, because to spend capital on a well to load it with more profit than you do it right. And the balance sheet is a different decision as to how you run that. But I don't expect us to change our views on the balance sheet.

And so, that's right if it makes sense on a well-by-well basis and where is the point, like in any play where is the point of diminishing returns? And does 2,000 ppf give you a nice bump, 2,000 pounds per foot, but 2500 ppf it's not worth the extra cost. That's what we'll work our way up to, the edge of the peak and see where that is.

There are many others in the industry, including in the Utica and even in the Marcellus, where they've gone to 2,500 ppf plus, and we ourselves, in our deep Utica test were above that, above 2,500 pounds per foot. So do believe it's feasible; it's just will it give you the economic return.

Okay, thanks, everyone, see you soon.

Thanks, Drew.

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 the call today. 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.