Antero Resources' (AR) CEO Paul Rady on Q4 2016 Results - Earnings Call Transcript

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Antero Resources Corporation (NYSE:AR) Q4 2016 Earnings Conference Call March 1, 2017 11:00 AM ET

Executives

Michael Kennedy - Vice President of Finance and Head of Investor Relations

Paul Rady - Chairman and Chief Executive Officer

Glen Warren - President and Chief Financial Officer

Analysts

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

David Deckelbaum - KeyBanc

Holly Stewart - Scotia Howard Weil

James Sullivan - Alembic Global Advisors LLC

Brian Singer - Goldman Sachs & Co.

Operator

Good day, and welcome to the Antero Resources Fourth Quarter 2016 Earnings Call Presentation. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded.

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

Michael Kennedy

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

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

Joining me on the call today are Paul Rady, Chairman and CEO; and Glen Warren, President and CFO.

I will now turn the call over to Paul.

Paul Rady

Thanks Mike, and thank you to everyone for listening to the call today.

In my comments, I am going to first provide a recap of our consolidation efforts within the basin in 2016. Secondly, review our overall development program throughout the year including some of the key encouraging pad results. And then thirdly, discuss cost efficiencies that we achieved in 2016.

Glen will then highlight our fourth quarter and full-year financial results including first of all, price realizations, secondly capital efficiency gains and thirdly EBITDAX margins. He will then provide a brief discussion on a couple of the recent NLG infrastructure announcements and the impact those announcements will have on our business. Lastly, he will touch on our long-term targets and outlook moving forward.

First, let's discuss Antero's 2016 acquisition activity and our efforts to consolidate the Appalachian Basin. We are the most active operator in the basin. We have a strong balance sheet and the largest contiguous acreage position in the core of the Marcellus and the Utica. We are therefore extremely well positioned to be a leading consolidator in these two place.

On Slide number two entitled, a leading consolidator in Appalachia, you can see the acreage we acquired in the Marcellus throughout 2016 highlighted in green which is shown in and amongst our existing acreage in yellow. In total we acquired approximately 74,000 net acreage in the core of the Marcellus and Utica shale place in 2016, including 64,000 net acreage in the Marcellus which is highlighted on the map.

In addition to our consolidation efforts I would also like to take the opportunity to point out a number of notable pads where we implemented advanced completion techniques in 2016, and which are now delivering some strong EUR results.

One of our recently completed pads that I will highlight is the 10 well Marcellus pad located in our highly rich gas area in West Virginia. This was significant as it represents one of our largest producing pads ever place to sales with a combined 30 day rate of 200 million cubic feet equivalent per day and that average process EUR of 2.6 Bcf equivalent per 1,000 feet of lateral assuming full ethane rejection. We estimate that the 10 wells on the pads will generate an average IRR of a 100% and payout in 1.7 years assuming current strip pricing.

You will also notice that each of the highlighted pads on the slide were completed with 1,500 pounds to 1,700 pounds of proppant per foot and are supporting average well head EURs at or above the 2.0 Bcf per 1,000 foot of lateral type curve.

Given the location of this acquired lease hold, we feel very good about our ability to achieve similar results on the nearby acquired acreage as well as on our existing surrounding acreage. Importantly, consolidation will enable us to continue to improve our drilling and completion, capital efficiency and drill longer laterals and more wells per pad.

Lastly, the vast maturity of the acquired acreage is undedicated to third-party midstream service providers. This provides Anteor midstream with additional organic growth opportunities and the ability to optimize existing infrastructure.

Now on to the 2016 development program. We executed our 2016 development program ahead of plan and under projects, while growing our production 24% year-over-year including 62% liquids production growth as compared to 2015. We completed and placed online 128 wells during 2016, including 88 in the Marcellus and 40 in the Utica.

By completing our 2016 plan ahead of schedule and under budget we were able to accelerate 18 wells into the fourth quarter of 2016 without a change to our 2016 drilling completion budget of $1.3 billion. This was primarily a function of the drilling efficiencies and cost reductions achieved in 2016.

On the cost front, we continued to drive down drilling and completion costs through both our operational efficiencies and service cost reductions. As highlighted on slide number 3, entitled continuous operating improvement.

By the fourth quarter of 2016, we had reduced Marcellus average drilling days from 24 days in 2015 to 12 days and increased our competition stages per day from 3.5 stages per day in 2015 to 4.0 stages.

Similarly in the Ohio, Utica by the fourth quarter of 2016, we had reduced our average drilling days from 31 days in 2015 to 13 days and increased our completion stages per day by 62% from 3.7 stages per day in 2015 to 6.0 stages per day.

These operational improvements combining with service cost reductions resulted in a nearly 30% improvement in fourth quarter 2016 well costs relative to 2015 costs, both in the Marcellus and the Ohio, Utica.

In combination with the reduction in well costs we also achieved significant productivity gains in 2016. To help provide more color, I’ll turn your attention to slide number 4, called improved productivity drives lower F&D costs.

As illustrated, on this slide the key operational shift during 2016 was to increase profit and water used per foot in each completion. In the Marcellus, we increased the profit and water used from approximately 1200 pound and 33 barrels in 2015 to 1500 pound in early to mid 2016 and then to £2000 and 46 barrels in the fourth quarter of 2016.

The increase to 1,500 pounds per foot resulted in a nearly 26% increase in the average EUR per 1,000 per foot lateral in the Marcellus to 2.4 Bcf equivalent per 1,000 assuming ethane rejection. When you combine and reduce well cost with this increased productivity the result is the significant reduction in overall fourth quarter 2016 F&D cost to $0.41 per Mcfe in the Marcellus and $0.68 per Mcfe in the Utica.

Looking ahead to 2017, we are reiterating our drilling in completion capital budget of $1.3 billion. We have in place long-term contracts for both completion crews and drilling rigs, and we are continuing to see efficiency gains. Therefore, we do not expect any meaningful increase to well cost in 2017. On the completion front, we expect to continue testing higher profits load in 2017.

As illustrated on Slide 5 entitled Marcellus Completion Evolution for our 2017 development plan, we expect to utilize 1,750 to 2,000 pounds per lateral put for the majority of our program and allows us conduct handful of pilots at 2,500 pounds per foot throughout the year.

Now I don’t want to jump around too much and confuse you, but if you refer back to slide number two, you can see that we are observing encouraging early results from the higher profit loads in the 2.5 Bcfe to 2.9 Bcfe per 1,000 foot range assuming ethane rejection. Ethane recovery takes those EURs to the 3.2 Bcf to 3.7 Bcf equivalent per 1,000 range.

Before I turn it over to Glen, let me just quickly recap 2016 from an operational perspective. During 2016, through the strategic acreage acquisitions I touched on earlier, we increased our core drilling inventory to over 3,400 locations with an average lateral length of 8,100 feet. This is by its higher the largest core drilling inventory in the South Western core of the Marcellus and Utica shelf place.

We have reduced well cost nearly 30% in both the Marcellus and Utica and improved overall recoveries in the Marcellus by 26%. The increased recoveries resulted in production growth of 24% during the year which beat our original 2016 production guidance by 8%.

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

Glen Warren

Thanks Paul. Let me begin with some of the key highlights from the quarter end here production average of record 1.99 Bcfe per day or essentially 2 Bcfe a day for the quarter, a 6% quarter-over-quarter increase including nearly 87,000 barrels of liquids.

Liquids production included 5,000 barrels a day of well, and just over 81,000 barrels per day of NLGs representing a 7% increase from the prior quarter as Antero remains the largest NLG producer in Appalachia.

This production outperformance continues to be driven by operational improvements, particularly associated with the advanced completion that were implemented in 2106, which Paul touched on his remarks.

Moving on realized pricing during the fourth quarter, we achieved outstanding results for both realized gas and liquids pricing. We realized a $0.07 premium to NYMEX Henry Hub or $3.05 dollars per Mcf of four hedges on our gas production during the quarter, which was $0.52 higher than our next closest peer and $0.78 per Mcf higher than the peer average. This further validates the strategic advantage of our extensive firm transportation portfolio enabling us to move firstly all of our gas away from unfavorable local Appalachian industries.

In fact, for full-year 2016, we were able to achieve a $0.04 for Mcf premium to NYMEX Henry Hub, which was at the higher end of our guidance of neutral to $0.05 premium. We realized a natural gas hedge gain of $187 million during the fourth quarter $1.38 per Mcf of gas produce and $957 million for the full-year or $1.89 per Mcf of gas produced during the year.

Moving forward we believe our firm transport and hedge will continue to be competitive advantages for Antero as uncertainty around both northeast basis differentials and overall gas pricing is likely to be continue.

As a reminder, for 2017 and 2018 we are 100% hedged on our expected gas production, a very high levels $3.63 per Mcf for 2017 and $3.91 per Mcf for 2018. In fact through the end of the decade, we are 85% hedged versus target gas production for Antero at $3.73 per MMBtu that’s kind of $0.82 per MMBtu premium to the current strip almost $1 premium to the current strip.

As it relates to liquids pricing we realized an un-hedged C3+ NGL price of $25.22 for barrel during the fourth quarter or 51% for the NYMEX WTI and an ethane price of $0.22 per gallon or $9.36 per barrel in the northeast. The C3+ NGL pricing of 51% in WTI during the quarter resulted in realized pricing equal to 43% of WTI for the full-year, which was well above our 2016 guidance of 35% to 40% of WTI.

The improvement in realized pricing was primarily driven by the strengthening of Mont Belvieu pricing relative to WTI with local differential slightly better than the prior year. The strengthening in Mont Belvieu pricing was primary result of increased demand for propane and butane as propane exports rose to the 1 million barrels a day of range.

During the quarter we generated $476 million consolidated EBITDAX, the company record detailed on slide number six titled highest EBITDAX and margins among peers. Our EBITDAX increased by 55% year-over-year and was almost $100 million higher than our next closest peer.

Our EBITDAX margin $2.31 per Mcfe after adjusting for the non-controlling interest in Antero midstream or $0.47 per Mcfe higher than that of our next closest peer. This is the further testaments our integrated business strategy, which includes best quality rock, firm transport and firm to favorable prices indices selling gas fixed prices and the highest exposure to liquids pricing upside in Appalachian. At the end of the day, the E&P business comes down to cash generation and real cash rates return and Antero has excelled in those areas quarter-after-quarter, as you can see.

Continuing on the liquids topic, I wanted to provide a few thoughts as it relates to recent NGLs infrastructure announcements. Our liquids-rich exposure and how that translate into increased cash flow as our liquid production growth continues.

Starting on NGL infrastructure and our control of liquids-rich resource base in Appalachia, I’ll direct you to slide number seven. As outlined in the pie chart in the middle of the bottom part of the slide, based on our detailed technical analysis, Antero holds 41% of the undrilled core liquids-rich locations in Appalachia.

This provides us with a tremendous leverage and visibility when it comes to the NGL infrastructure build out in the play. You can see in the lower right on slide number seven that our acreage position is well connected to significant NGL processing fractionation and key long transportation projects that move our product to market.

Antero mid-stream which we owned at 59% interest in, recently announced a joint venture with MarkWest related to the build out of future processing and fractionation facilities. This is very important to Antero resources as it provides us with tremendous clarity and certainly around the next 11 Antero dedicated processing plants to 2.2 Bcf a day of processing capacity in the Marcellus.

Given our long-term growth targets, it's essential that we are able to secure access to and some control over the timing of future processing and fractionation infrastructure. Continuing on this topic, Sunoco Logistics recently announced that it is received the permits needed to proceed with construction of Mariner East 2.

Upon completion of ME 2 expected in the third quarter of this year, Antero will be able to minimize the expensive rail transport to Mont Belvieu and other domestics NGL markets and move our NGLs to our pipeline to market serve and on to export markets. Antero is an anchor shipper on ME 2 with a 61,500 barrels a day commitment for propane, butane and ethane.

Moving on to the pricing outlook for liquids, I will point to the slide number eight, titled Arising Liquid Price Environment. On this slide you can see the expected improvement in [WTI] NGL pricing sheeted in green as well as our realized C3+ NGL pricing in 2015 and 2016 which we shaded in yellow. Importantly we expect these trends to continue in 2017 and as a result we have raised our guidance which previously was 45% to 50% of WTI to now 50% to 55% of WTI for 2017.

This increased C3+ NGL price realization guidance results in an incremental $65 million to $70 million of un-hedged EBITDA in 2017 based on our 2017 C3+ NGL production guidance of 65,000 to 70,000 barrels per day. Once Mariner East 2 is placed in service, we expect further improvement in NGL net back pricing resulting in C3+ NGL price realizations, up 55% to 60% of WTI in 2018.

It is important to note the increase in 2017 guidance and 2018 target pricing included in the slide, presently based on current share pricing and a blended C3+ NGL barrel for a [1225] (Ph) average of BTU location. We haven't assumed any incremental upside from an improvement in oil prices for the strengthening of Mont Belvieu NGL prices or look as differentials. In addition to our arising liquids price environment, I assume that liquids-rich inventory enables us to achieve tremendous growth on our liquids production.

As shown on slide number nine, titled Rapidly Growing NGL Production. We have increased our NGL production by 93% on a compounded annual growth rate since 2014. And expect to grow to around of 150,000 barrels per day by 2020.

Moving on slide number 10, when you combined the rising liquids price environment with this top-tier liquids production growth, you can really see the exposure Antero has to NGLs and the incremental impact of liquids pricing and production on our future EBITDAX.

To help orient you to the page I will pointed to the yellow line on the chart to the right. This line represents the expected incremental EBITDAX above 2016 levels assuming $55 oil and realized C3+ NGL pricing 52.5% of WTI.

For example, the red circle number of $332 million represents the incremental un-hedged EBITDAX attributable to liquids production that we would achieve in 2017 relative to 2016. The increase is driven by incremental NGL production above 2016 levels and expected improved NGL pricing above 2016 pricing. The green and blue lines represent incremental EBITDAX at additional pricing scenarios assuming our targeted NGL production levels through 2020.

So to summarize our NGL story with the largest NGL producer in Appalachia today and control over 14% of the undrilled core liquids rich locations. We are significantly interconnected to key NGL infrastructure through the recently announced joint venture between Antero Midstream and MarkWest and our commitment to Mariner East 2.

With the back drop of rising liquids prices and continued growth in liquids production, we are very well positioned to capitalize on the strong fundamentals and substantially grow our cash flow over the next several years.

Before I finish up, I wanted to briefly discuss our future outlook through the end of the decade, I will direct you to slide number 11, titled 2017 Guidance And Long-Term Outlook. We plan to grow production by 20% to 25% over 2016 guidance to 2.2 Bcfe per day in 2017, while targeting annual production growth of 20% to 22% thereafter through 2020.

Also notice the redlines, the numbers on the production bars that displayed beside volume and price level of our hedges particularity through the 2017 to 2019 period. We expect to achieve this growth while maintaining a drilling completion budget within consolidated cash flow from operations through year 2020.

Slide number 12, entitled significant cash flow growth drives declining leverage profile demonstrates that as our asset base further matures and our cash flow continues to grow as you could see on the yellow bars here. We also expect our overall leverage to decline into the mid [2s] (Ph) by next year and beyond and that’s the green sweeping line that you see there.

Now finishing up on slide number 13 entitled capital efficiency driving cash flow growth, this illustrates how after several years of outstanding to build the production base in the business DMC capital spending is now in line with cash flow, we believe that this marks an inflection point for Antero, the future is quite bright.

With that, I will turn over the call back to the Operator. Thank you.

Question-and-Answer Session

Operator

We will now begin the question-and-answer session. [Operator Instructions] And the first question is from Neal Dingmann with SunTrust. Please go ahead.

Neal Dingmann

Good morning guys. Say particular up to and dig in on that 10 well pad, Marcellus pad, you all mentioned to have that exceptional 1.7 either cash-on-cash, you mentioned on the longer laterals in the San. I guess I’m just wondering on that or in that area location wise, is there still - I mean if you kind of give me some color, is there a lot of acreage that kind of fits that parameters on those 9,000 to 11,000 foot laterals and then kind of in that same vicinity?

Paul Rady

Hi, Neal. Yes absolutely, there is a lot of lateral locations to there, we are pretty solid yellow for many miles and it fits in terms of BTU yield and pressure. So it should have many, many more locations like that there.

Neal Dingmann

And then on those, you mentioned kind of with that cash-on-cash, does that assume some inflation on there and is that the well that you have locked in about 70% of your cost, in order to achieve that that’s the nominal cash-on-cash payout?

Paul Rady

Yes, I means that cash-on-cash payout is the - that’s specific to that pads to so those cost already are standard costs, but we do not have any acceleration built into our service cost in the budget for this year. We can hit on that in greater detail if you like. But we have 90% of our drilling rigs and completion crews under contract this year, and about two-thirds in 2018. You can see that on Slide 20 and our website presentation for March.

And within those completion contracts we were concerned about sand cost and all. We have escalators built in there, but they are tied with things like PPI and CPI and labor indices and some of the sand contracts have in oil index escalator if oil prices go up. But other than that, we are not going to be subject to spots sand prices with those completion crews. It's pretty well time now to various indices.

So for that reason, we haven't built and escalation and service cost into our budget for this year; plus we seeing a lots of efficiencies continue in both the Marcellus and the Utica as you could see, we don’t think that’s going to stop and sort of thirdly the EURs are continuing to improve as well. So we are pretty comfortable with that. We didn’t chase the service cost down last year by lowering our budget, we use sort of our contracted numbers in our AFEs.

Neal Dingmann

And then the last one if I could, just on the NGLs, you guys are doing obviously phenomenal job with the realization there, what is the hedge market a year or two, three out, has that market become much more fluid than it once was? Are you able to continue locking these great realization, I guess what I am asking?

Glen Warren

Yes, the hedge market is there or at least two maybe three years out. One can hedge ethane, propane and butanes and if one wants to butane is a little less liquid. I will emphasis in term of our presentation, we blend in the gas and the liquids hedges together and then it comes out to 60% or so. But in reality the detail is that we are 100% hedge down gas and quite un-hedged on all of our liquids.

We are about 75% hedge this year on propane and then un-hedged for Cal 18 and beyond and the same would be other products. So yes, there are markets out there where we can hedge and we will be adding hedges, but right now we see upside in liquids, we see it because of increasing demand as well as improving infrastructure. So we will be hedging as we go through time, but we are quite well exposed to the upside that we are seeing in liquids.

Neal Dingmann

Very good, Paul, Glen, thanks. Great quarter.

Paul Rady

Thank you, Neal.

Operator

Our next question comes from David Deckelbaum with KeyBanc. Please go ahead.

David Deckelbaum

Good morning, everyone. Thanks, Paul and Glen for taking my questions.

Paul Rady

Hi, David.

David Deckelbaum

I was just curious to ask just to ask and I guess can you guys give us some color on how you are thinking about ramping your volumes for Rover and I kind of you split out that you guys have allocated right now in the Utica for sort of dry locations versus rich gas which seems to be more rich gas oriented now, which imagine more IRR driven. Is there any thought around little bit more aggressive activity in the [dry] (Ph) gas window, the Utica and preparation for sort of Rover startup?

A - Paul Rady

Yes, we are definitely of course looking forward to the Rover startup, the announced date is July and so we are prepared to begin filling as soon as it opens, we might risk that a little bit or at least we are prepared and opens later, but expected to be there in July. We do have a pretty good split between Utica dry gas and Marcellus rich.

At the current times, the Marcellus rich gas does have better economics than the Utica that we are making great progress on that Utica drive really getting the well cost down there. We will be juggling back and forth our CapEx budget between each of the place, but as we are rapidly building out our processing complex it sure would, but do have to tie in capital spending on the Marcellus side, tie that all into liquids infrastructure too. So there will be some adjusting back and forth for Rover, but it needs to match all of our other FT and processing.

David Deckelbaum

Appreciate that. And I guess my other question is, you guys highlight sort of the excess cash that anticipate generating your fairly highly hedged obviously quite a number of years now, so it’s fair to say looks like the program is well cover. Should we be thinking about the uses of excess cash in you are sort of long-term program that continue consolidating the Appalachian area or are you starting to look outside the basin just given that you kind of highlight that you have I guess 40%, 50% sort of the undrilled locations in the liquids rich core there?

Paul Rady

Yes, consolidation is certainly filling our minds and we will continue to consolidate and so that’s one you just have the cash this anything significant there we think beyond just certainly cash flow, but the other notice we are talking about consolidated cash flow from operations relative to DMC and we are pretty well covered there, but we do have other spending along the lines with midstream spending, because we have given you a consolidated number there. So not completely at the point of showing free cash flow yet over the next few years. We will be continuing to invest in the midstream business.

David Deckelbaum

All right. Thanks guys.

Paul Rady

Thank you.

Glen Warren

Thank you.

Operator

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

Holly Stewart

Good morning gentlemen. Maybe taking through Slide 10 a little bit, with just the C3+ uplift maybe taking a step further. What your thoughts right now on I think extraction versus rejection? And then what are your constrains there, if any I see the ethane guidance for 2017?

Paul Rady

Well, if you look at our 3P reserves we have got well over 1 billion barrels of ethane and so we have a lot. We will be supporting local markets, we have talked about that crackers and such, but right now we are recovering in the low to mid 20,000 barrel a day range of ethane and then the rest we are rejecting leading in the stream, just because of the ethane economics.

All-in so not some cost, but if for new cost new tariffs and so on, we need to be in the mid 30s and ethane $0.35 plus a gallon in order to pay extract the ethane and ship it to Belvieu. And right now the future's curve does begin to go out there, in the near-term, it's $0.28, $0.29 a gallon and kicks out into the $0.34 range.

So we are seeing some uplift there and getting close what we have been doing is as I say leaving it in the stream as we supply to crackers and the export those have a mix of gas plus and upside of Belvieu upside. So get pretty good prices that are a little bit different than just a straight extraction tariff and sell at Belvieu. So we will be extracting more.

Our [indiscernible] right now at Sherwood is for 40,000 barrels a day. MarkWest will build another one for us another 20,000 barrel a day at least as we go forward, as we prepare for some of the markets, local markets as well as the good at Mariner East 2 is that we will be exporting ethane to Borealis as soon as that opens for another 11,000 barrels a day and we will be open for business there on ethane for more international exports and again that pricing structure is such that it does pay to recover and we did a good flow or plus and upside as liquids rise.

Holly Stewart

Perfect, and then Paul maybe a follow up to that, it's sound like ME 2 is at least - or ME 2X is at least going to move forward at this point, any thoughts on that commitment to that project at this time?

Paul Rady

Well, we are of course leased that ME 2 is going forward and we believe that it will be in service by the fall, we are glad ME 2X can go forward as well and that just opens up opportunities for us. We haven't thought yet about committing more to ME 2X, but we certainly would with the right pricing and the right international markets developing.

Holly Stewart

Okay. And then maybe just a quick modeling one if I could, any lumpiness to think about in terms of the quarterly production volume cadence?

Glen Warren

No, I think it should be fairly steady throughout the year Holly, we expect to see continuing ramp up, I wouldn’t say would be particularly lumpy I think it’s fairly steady completion schedule throughout the year. We are watching Rover closely and I think once see the space in the ground, we may want to accelerate some of the DUCs that we are going to carry in the Utica into next year.

We are planning to finish this year with about 30 DUCs expecting Rover to potentially be into 2018. So I think if that does come to fruition and they are actually plain pipe and then you may see some acceleration there of DUCs bringing more completions into the third and fourth quarter in the Utica. But that’s the only thing I could think of right now, it’s pretty steady.

Holly Stewart

Okay. That’s helpful. Thank you, guys.

Paul Rady

Thank you.

Operator

And our next question is from James Sullivan with Alembic Global. Please go ahead.

James Sullivan

Hey, good morning, guys. Thanks for taking the questions. If I could just ask you a little bit again prime marketing on your marketing guidance, once you guys see the ET is space in the ground for Rover, do you guys had a plan for certainly up that in our segment that you guys target to pick back up from them and is that any anticipated increase marketing expense in the guidance there?

Paul Rady

Yes, so as Rover and something expansions go into the Michigan, Chicago area. So that would be Rover and others that goes to defiance, if there is a the ANR capacity is by directional and so if prices are better in the Gulf then we will be able to move our gas as well as excess gas any build up in the Michigan and Chicago markets to the Gulf, so that will be the early stage and then as we fill up Rover ourselves and expect to probably move that down ANR and capture any premium in the Gulf and also just supply the LNG projects that we are producers for such as [indiscernible].

James Sullivan

Okay. So the idea would be that taking that FT from the Rover team there, you would be able to pick up I mean excess cash just pick it up from mid last rather from Appalachia?

Paul Rady

Yes, that’s right. That ANR goes from or from REX Zone 3 from Shelby, Indiana and also the defiance it goes south to the Gulf. So that would be third-party plus Antero gas. And yes we will contractually energy transfer turns that back over to us as it becomes in service to the Seneca complex in Ohio.

James Sullivan

And then lastly, could you guys just going back to the liquids for a second, could you comment on kind of any particular market strength in the Northeast for a propane and to what extent that impacted your obviously impressive C3+ realization that you had in the quarter. And any sense do you guys have durable that [indiscernible].

Glen Warren

I think the demand in the North East is fairly steady that the local demand and rail rates have come down quite a bit which has helped us differential for railing products in the interim between now and the startup of ME 2. But once ME 2 comes online, you have quite a take away option there, they are going to have 275,000 barrels a day of capacity on that pie go into market so that can enabling export there. So we feel pretty good about that whole scenario that’s why we are bullish on raising the guidance for this year for our NGL pricing relative to WTI.

James Sullivan

Okay great. And then if I could squeeze one in here, do you guys have any color or any updates on year-over-year assessment of the demand for the end markets perhaps for LPG [indiscernible] for the conversations like in those guidance in terms of looking for more of a score volumes?

Glen Warren

Jim, I heard your question right, that was the outlook on the LPG markets is strong, it's booming, and so we will be able to - we have capacity that we can use on Mariner, it's penciled then as propane but it is both propane and butane technically and it can be a mix and it can be made to at the right combinations to serve the different LPG markets in the Atlantic basin. So that is really emerging as another demand source out of markets look. And so we think that has a bright outlook.

James Sullivan

Great thank you guys. Appreciate it.

Glen Warren

Thank you.

Operator

Our next question is from Brian Singer with Goldman Sachs. Please go ahead.

Brian Singer

Thank you good morning.

Paul Rady

Hi, Brian.

Glen Warren

Hi, Brian.

Brian Singer

My first is follow-up on with regards to one of the earlier questions here, when we think about the productivity gains, the potentials to cost inflation and pipeline and associate tariff coming on, how do you think about your operating costs per Mcfe over the next couple of years, less so in 2017, but just more what is that trajectory is, given the visibility of production in some of these tariffs?

Paul Rady

Yes, we have already got in service quite a bit of our FT portfolio, so we don’t expect a large increase in the flow through from FT to operating cost. But I mean it goes up by a few penny over the next few years. So not significant.

Brian Singer

Got it, okay thanks and then on the completion front, you continue to highlight the increases in profit loading, can you talk more about your expectations for EURs for the 2,500 pounds per foot, lateral that the relationship that you see between profit loading EUR and where is that all of you see constraints profit loading wise?

Glen Warren

That’s a good question Brian and that is why we are running the pilots, we are not sure where the break over point of diminishing returns will be. We are very early in the 2,500 pound, the expectation of course would be that it's better than the 2,000 pound, but we don’t know yet.

So expect to have good results that we should see and even we will have to see initial rates and then watch the curves overtime. We are pretty conservative and we will be watching to see if it's were the extra effort. We think it will work, we think it will be good, and that’s why we want to do it early while we still have 3000 or 4000 more locations to drill just to figure it out on the early end, but it is early.

Brian Singer

Thanks and you may have said this already, but what is the incremental costs for the 2,500 versus the 2,000.

Glen Warren

Not much, less than 10% per say.

Brian Singer

Got it. Thank you.

Paul Rady

Yes, thanks, Brian.

Operator

And our next question is a follow-up from David Deckelbaum with KeyBanc. Please go ahead.

Paul Rady

Hi, David.

David Deckelbaum

Thanks, guys. Sorry to hop back in here with one more. But just wanted to just ask about, at least in the press release you guys discussed that a portion of your wells in the Utica are going to be on existing pads this year. I wanted to ask sort of the pointing that out in the press release is that more of an indication your cycle times in the Utica should be relatively compressed this year this of is this sort of a new strategy to test kind of reentering existing pads across Appalachia and leverage some of the costs that you have kind of already sunk in there?

Paul Rady

Well, I think maybe it signals through, but it especially just reflects the fact that these are big pads and typically when we get out of pad we will have four or five wells going in one direction in kind of a pitchfork pattern. And we will move off just because of that cycle time I think 180 days are more to drill and to complete and so the sales delay is a little bit of an affecting there.

So we come and we build the pad, we drill them all in one direction, frac them out, put them online and then come back at a later date maybe a year later and get on the same pad and drill on the other direction. And so it’s just away to reduce the cycle time and so I think you think it will reflect it will have shorter cycle times in the future when we go back to existing pads that it’s much more quick in and out and the infrastructure is there.

We do have plenty of pads where we have just drilled pitchfork in one direction and can come back and drill on the other direction. So we have been saving these and these definitely fit into our drilling schedule.

Glen Warren

But and to follow-on to that David, I mean when you are drilling $10 million to $15 million kind of MPV wells then that doesn’t really move the needle a whole lot, it’s really more about where you have infrastructure and what are the best locations to drill.

David Deckelbaum

Got it. So this is more kind of a coincident of the Utica program, which I guess will start to showing up I guess in the Marcellus program overtime.

Paul Rady

It’s true and one more add on that to what Glen just said our typical compressor stations might be 120 million, 160 million a day and you can see when you bring on pads you max out the compression just with the pitchfork in one direction. So part of the coming in and then moving of a pad half way through it is to fit the infrastructure.

David Deckelbaum

Thanks for taking the follow-up guys.

David Deckelbaum

Thank you.

Operator

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

Michael Kennedy

Thank you for participating in today’s conference call. If you have any further questions, please feel free to contact us. Thanks again.

Operator

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

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