Michael N. Kennedy - Vice President-Finance & Head-Investor Relations Glen C. Warren - President, CFO, Secretary & Director Paul M. Rady - Chairman & Chief Executive Officer.

Holly Barrett Stewart - Scotia Howard Weil Arun Jayaram - JPMorgan Securities LLC James Sullivan - Alembic Global Advisors LLC Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc. Kevin MacCurdy - Heikkinen Energy Advisors LLC.

Good day, and welcome to the Antero Resources Fourth Quarter and Year End 2015 Earnings Conference Call and Webcast. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. 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 Fourth Quarter and Full Year 2015 Investor Conference Call. We'll spend a few minutes going through the financial and operational highlights and then we'll open it up for Q&A.

I would also like to direct you to the 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 the call today. In my comments, I'm going to highlight our recently announced 2016 capital budget and guidance, provide or review fourth quarter price realizations and expectations going forward and cover our fourth quarter financial results.

Paul will then review our 2015 drilling program and the cost efficiencies we achieved throughout the year highlight early results we're seeing on our first Utica well in West Virginia and discuss the operational flexibility we've created to react to material commodity price movements up or down.

Lastly during our comments both Paul and I will periodically refer you to a handful of slides that are located in a separate conference call presentation on our homepage entitled fourth quarter 2015 earnings call presentation.

This is separate from our monthly investor presentation also located on our website, so please make sure you are viewing the correct slide deck during the call. Now onto our prepared comments. Let's first discuss our 2016 capital budget and guidance which we announced last week.

Our total budget for 2016 is $1.4 billion, which includes $1.3 billion for drilling and completion capital and $100 million for leasehold activity. This represents a 23% reduction compared to 2015 spending levels and a 58% reduction compared to 2014 spending levels.

Driven by our current momentum and operational efficiencies, we expect to continue delivering top-tier production growth with 15% year-over-year growth expected in 2016 and 20% growth targeted for 2017.

Our growth in the second half of 2016 and 2017 will be a key attribute for us as many E&P companies will shrink their business during this period as their lack of investment catches up. Due to our solid well economics and outstanding hedge book, we are not forced to rob 2017 momentum in order to drastically reduce CapEx.

Additionally, we have structured our development plan in a manner that provides us with significant operational flexibility throughout the year to react to material commodity price movements up or down, which Paul will touch on further in his remarks.

Now, let me take a step back to give a little more color to our 2016 budget and how we think about the business which differs from many of our peers. As a leader in the shale revolution over the past 10 years, we recognized early the paradigm shift in how operators must differentiate themselves.

In the past, operators focused heavily on the land grab as resource plays were being delineated and developed.

Now, that the rock has generally been identified and core positions established for North American shale plays, not only do operators need to distinguish themselves based on their asset base, but also on their ability to efficiently develop and maximize the return on the asset base. The capability to commercialize the asset base is critical.

So, how do we distinguish ourselves versus our peers? Let's first touch on the hedge book. As this is a key differentiator for Antero versus our peer group today, I think it's extremely important to look at how the hedge book was actually constructed.

We began building this hedge book more than five years ago and have systematically hedged our risk over this time period rather than trying to lock in pricing when it was too late as the futures curve rolled forward, eroding the Contango.

For us this strategy eliminated the problem many E&P have faced over the past year which is the reluctance to hedge at such depressed prices for the short-term as commodity prices have continued to fall due to the oversupply.

Our strategy has also been to sell forward our undeveloped gas at prices that we know will generate strong returns and that has paid off too.

As you can see on slide number two in that deck titled Hedging Future Drilling, we've essentially hedged 100% of our production including all of our undeveloped production from yet to be drilled wells through 2017 at attractive prices of $3.94 per MMBtu and $3.57 per MMBtu respectively.

To provide additional context around our hedge book, I'll refer you to slide number three titled Highest Proportion Hedged among E&P Operators.

On this slide and based on our 2016 guidance, our 2017 target, and 2018 consensus estimates, you can see we've hedged on average 94% of our expected production through 2018 at a hedge price of $3.81 per MMBtu. This compares to the peer group average over the same time period of just 20% hedged.

The cash flow protection for this hedge book has provided us with a conviction and ability to enter into long-term commitments including gathering, processing, and most importantly, firm transportation.

Most of the firm transport portfolio was constructed over the three years ago to secure the cheapest transportation, which means reversals and backhauls with the majority targeting the Gulf Coast.

The firm transportation portfolio accommodates our long-term development strategy and maximizes product realization by providing access to the most favorable priced markets.

As you can see on slide number four titled Realized Price Road Map, we expect to receive premium pricing to NYMEX for 2016 and beyond as we project gas sales to favorable markets to increase from 69% in 2015 to essentially 100% in 2016 and 2017.

Due to our ability to access the best markets for virtually all of our gas volumes, we have guided to a premium to NYMEX of $0.00 to $0.10 per Mcfe including the BTU upgrade resulting from the ethane projection. So, a positive basis differential.

We're likely the first Appalachian producer to forecast a positive basis differential to NYMEX in recent times.

On slide number five titled Firm Transport and Sales Portfolio, you can see that we were able to secure this firm transportation portfolio with only approximately $100 million in net marketing expenses in 2016 and similar amounts in the future until our production fills our capacity closer to the end of the decade.

That's $0.15 to $0.20 per Mcfe of net marketing expense in 2016. The first half of 2016 has higher FT capacity, and is expected to result in a higher net marketing expense run rate. However, we are off to a strong start to the year as January net marketing expense came in at approximately $10 million, which was ahead of expectations.

When you compare the $100 million of net marketing expenses for the full year 2016 to the 1.1 billion of expected hedge proceeds during 2016 and the positive basis differential to NYMEX, you can see the FT portfolio is delivering substantial value to Antero.

In addition to the hedge book providing us with a conviction to build our long-term diverse firm transportion portfolio, the hedges also help offset the risk of borrowing base reductions from lower-priced decks.

This allows us to enjoy significant liquidity that we can count on due to this ability of our bank borrowing base; it also gives us more comfort around our development plan that targets peer-leading growth.

As you see on slide number six titled Borrowing Base Increase Relative to the Peers, Antero was only – was one of only a few operators during the fall of 2015 redetermination season that increased its borrowing base, increasing it by $500 million to $4.5 billion.

Based on the committed available capacity of $2.6 billion under our credit facility at year end and our locked-in revenues, we have the ability to fully fund our development program for the foreseeable futures with our hedges and credit facility alone.

Staying on the strength of our balance sheet, I'd like to briefly touch on the recently announced affirmed ratings we received from Moody's and S&P relative to other E&P operators.

As highlighted on slide number seven entitled Antero Credit Quality Affirmed at Ba2/BB, Antero was only – was one of only five public Baa or Ba rated E&P companies that received affirmed ratings from Moody's during its recent thorough review and one of only two public Ba rated E&P companies that received affirmed ratings.

The other 16 Baa and Ba rated companies received downgrades ranging from one to five notches. Out of the group, 12 public companies rated Ba prior to the review, Antero moved from the eighth highest rated Ba producer out of 12 to the fourth highest Ba rated producer out of eight following the review.

And that was after five investment grade E&Ps were downgraded to Ba or B. In fact, eight of the 12 public previously Ba rated companies were downgraded to B or even CCC levels.

This reaffirmation supports our continued message that we are much better positioned than most of our peers to execute on our business plan in the current downturn and have the flexibility to further adjust our development plan up or down depending on commodity prices.

Now, on to fourth quarter price realizations, during the quarter there were some significant developments that occurred as it relates to our natural gas sales volumes. First, the Stonewall pipeline was placed in service November 30.

This pipeline has enabled us to shift volume from the unfavorable Dominion South and TETCO M2 price indices to more favorable TCO, NYMEX and Gulf Coast-based pricing.

In conjunction with the Stonewall Pipeline being placed in service, we also executed on the early termination of a 130 million cubic feet a day firm sales agreement that was contracted at Dominion South base pricing, shifting that 130 million cubic feet a day to the TCO index.

While the termination charge associated with this contract showed up as a $28 million non-cash termination expense in the fourth quarter, the volume shift from the Dominion South to TCO index will enable us to realize approximately $60 million of incremental revenue over the next two years based on current strip pricing.

What does this all mean from a price realization standpoint? If you refer to slide number eight titled Fourth Quarter Natural Gas Realizations, you can see we received a $0.14 per Mcf negative differential to NYMEX during the quarter before hedging, or $0.38 higher than the average from the peer group that's reported so far.

Importantly, when Stonewall was placed in service we realized a $0.01 per Mcf premium to NYMEX before hedging for the month of December. We sold 83% of our production at favorable indices in the quarter including Chicago, Gulf Coast NYMEX and TCO which was an increase from 68% of gas we sold to favorable indices in the prior quarter.

We also had natural gas settled hedge gains of $244 million or $2.27 per Mcf in the quarter. Including these hedge gains, our realized natural gas price was $4.40 per Mcf or a $2.13 premium to NYMEX. This is $1.40 per Mcf higher than our next closest peer thus far and $1.62 per Mcf higher than the peer average to date.

Our realized natural gas price continues to be the most attractive of our Marcellus peers driven primarily by the geographic location of our production, our significant hedge book and our diverse firm transport accessing favorable markets.

On the NGL front, we realized $17.37 per C3 plus barrel before hedging or 41% of WTI; and $21.65 per C3 plus barrel after hedging, or 52% of WTI. We are 100% hedged on propane in 2016 at $0.59 per gallon and gain access to international markets in 2017 through Mariner East II capacity, once in service.

Rounding out my comments today, let's touch on quarterly financial results. Adjusted net revenue increased 8% from the prior-year quarter to $630 million on 18% higher net production. Per unit cash production expenses were $1.46 per Mcfe, a 5% decrease compared to $1.54 per Mcfe in the prior-year quarter.

As a reminder, our production expenses include leased operating expense, gathering compression, processing, transportation as well as production tax. Our G&A expense for the quarter was $0.27 per Mcfe, excluding non-cash stock compensation expense, driven slightly higher by some one-time items.

As expected our net marketing expense was $0.38 per Mcfe, the result of gaining additional capacity on two new pipelines during the quarter. The first pipeline, Tennessee Gas came online November 1, 2015; however, we were not able to utilize it until December 1 when the Stonewall Pipeline was commissioned.

The startup costs related to these two pipelines was approximately $15 million or $0.11 per Mcfe that's $0.11 of that $0.38 per Mcfe for the quarter. Following Stonewall in service-date, we have increased our utilization from 55% in December 2015 to 80% in January of this year, so you can see the trend there.

Adjusted EBITDAX for the fourth quarter was $308 million, 7% lower than the prior-year quarter primarily due to decreased product revenue from lower commodity prices. Lastly for the quarter, we reported adjusted net income of $54 million or $0.20 per share.

Before I turn it over to Paul to cover our development program and our operational results, I'd like to summarize the quarter and outlook moving forward. We continue to achieve tremendous growth with natural gas industry-leading price realizations and peer-leading cash margins.

We built a highly sustainable business model with a large and growing production base a market leading firm transportation position, a significant long-term hedge position with a mark-to-market value of $3.3 billion as of January 31, 2016 strip pricing and $3.5 billion of consolidated liquidity under our credit facility since year-end, driven by the incremental firm transport recently placed in service in the Marcellus.

We are forecasting a premium to NYMEX before our hedges on our natural gas production in 2016 and beyond. We built a business model that truly works in the bottom of the cycle and thrives as prices recover. With that, I'll turn it over to Paul for his comments..

Thanks, Glen. In my comments today, I am going to review results from our 2015 development program, highlighting our low development cost nature, provide a brief update on our first Utica well in West Virginia, it's called the Rymer 4HD and further discuss the operational flexibility that we have built into our 2016 development plan.

First, let's discuss the 2015 development plan. We executed our 2015 development program ahead of plan, growing our production some 48% year-over-year despite shutting an approximately 45 million cubic feet equivalent per day of production during the fourth quarter due to the weak local pricing at Dominion South and the Tetco M2 index.

As Glen touched on, after gaining access to the Stonewall Pipeline late in the quarter, we were able to shift virtually all of this locally priced gas being sold at Dominion South and Tetco M2 indices to the more favorable TCO and Gulf Coast indices. So we are less susceptible to further shut-ins due to weak local pricing.

On the cost front, we achieved a number of operational efficiencies and service cost reductions driving down drilling costs throughout the year. In the Marcellus, we improved our average drilling days from 29 days to 24 days and increased our completion stages per day by 8%.

In the Utica, we improved our average drilling days from 34 days to 30 days and increased our completion stages per day by 17% as compared to 2014. These operational improvements combined with service cost reductions, resulted in a 16% and 18% improvement in 2015 well costs relative to 2014 costs in the Marcellus and Utica respectively.

Looking ahead to 2017 based on the current spot market rates we are seeing today for rigs and completion crews, we believe we can achieve an additional 12% in cost savings just from letting legacy rig and completion crew contracts roll-off over the course of 2016.

This does not include any additional cost savings from continued operational efficiencies. Moving on to our first Utica well test in West Virginia, we completed the Rymer 4HD well in Tyler County, West Virginia with the 6,620 foot lateral in late December.

As you can see on slide number nine, entitled Antero's First Utica Dry Gas Well, the well's been on sales for 60 days and has produced at a restricted daily rate of approximately 20 million cubic feet, which was our original plan, yielding a total of 1.2 Bcf during the two-month period.

We'll continue to analyze the flow back data, which will give us a much better understanding of the geologic characteristics and overall resource potential of the dry Utica in West Virginia. I will say that our early results are very encouraging and appear to be consistent with other strong results announced by operators near our acreage position.

Obviously economics will drive the pace and the volume of drilling, however, you can also expect development to be closely tied to takeaway and to gas price realizations making it more attractive for operators such as ourselves with the ability to access premium markets.

Our ability to access premium markets for the Utica dry gas is currently tied to the Rover Pipeline, which is scheduled to be in service in mid-2017.

To further touch on our 2016 development program, I want to highlight the operational flexibility we built into the program and also discuss the well economics associated with the targeted development plan.

First, on the operational flexibility, we have structured our 2016 development program to provide us with significant optionality to react to material changes in commodity prices up or down throughout the year.

We're currently planning on completing 80 wells in the Marcellus and 30 wells in the Utica with average lateral lengths of 9,000 and 8,800 feet, respectively. However, we do have the ability to reduce our current $1.3 billion development plan as six of our contracted rigs expire over the course of the year.

Our current budget assumes we will renew or pick up additional spot rigs as some of the contracted rigs expire, but again we have the flexibility to go either way. We may not renew or pick up spot rigs, but to the extent commodity prices materially improve from current levels we are well-positioned to accelerate activity.

As a result of our sizable inventory of drilled but uncompleted wells, which is expected to increase from 50 wells currently to approximately 70 by year-end 2016.

We are able to target 20% production growth in 2017 due to this inventory of drilled but uncompleted wells, coupled with our hedge revenue, which will allow us to deliver 20% growth while living within cash flow if necessary. Lastly, before I wrap up, I'd like to touch on our current inventory and well economics assuming year-end 2015 Strip pricing.

As outlined on slide number 10, we have nearly 2000 undrilled liquids-rich locations between the Marcellus and Utica Shale plays that generate low 20% to mid 30% rates of return based on current Strip pricing. These locations span the 1,250 to 1,350 plus Btu spectrum in the Marcellus and the 1,175 to 1,235 Btu spectrum in the Utica.

Additionally, we have over 250 Utica dry locations in Ohio that have approximately 25% rates of return at yearend 2015 strip pricing and this of course excludes the almost 1,900 locations associated with our West Virginia and Pennsylvania Utica dry gas resource.

Certainly, our current test, the Rymer 4HD well I just mentioned will provide additional insight on Utica dry gas well recoveries in both Ohio and West Virginia, Pennsylvania and combined with continued operational gains will give clarity on well economics over time.

It's worth mentioning that when you incorporate the hedge book in order to arrive at a blended gas and NGL price, these rates of return increase dramatically to a range of mid-40% to mid-80%.

As Glen pointed out in his remarks and as illustrated on slide number two, we have hedged virtually all of our undeveloped production through 2017 as well as an additional 2.1 Tcf equivalent for the 2018 to 2022 time period so we do feel the blended hedge returns are relevant.

Lastly, we regularly encounter questions around what assumptions are included in our single well economics. Antero believes in transparency and allowing others' due diligence and replicate our analysis.

And so consequently, we've elected to fully burden our single well economics with all pad and facility costs as well as all cash production expenses including midstream costs and firm transportation costs.

Importantly, the midstream costs contain a burden for Antero Midstream related fees and the firm transportation costs include both the fixed and variable cost components associated with our flowing gas on the downstream pipe.

While both Glen and I have highlighted many of the reasons we believe Antero is differentiated from our peer group, we think it's essential to let the data speak for itself.

If you look at slide number 11 entitled Antero EBITDAX Outperformance, you can see that Antero's fourth quarter EBITDAX totaled $308 million as we had achieved an EBITDAX margin of $2.03 per Mcfe.

As illustrated on the top half of the page, we generated approximately $60 million higher EBITDAX than our next closest peer during the quarter and only 7% less EBITDAX than the prior year quarter, despite a 43% drop in both oil and natural gas prices during the year.

The peer group on average generated $100 million less in EBITDAX compared to the prior year quarter or 31% lower on average. Pointing to the bottom half of that page, over the last five quarters, we have consistently achieved peer leading EBITDAX margins among our peer group.

We outperformed the average peer group EBITDAX margin by 26% in the fourth quarter. We expect our leadership and outperformance in Appalachia to strengthen over time.

In summary, we had an outstanding 2015 development program that resulted in peer leading growth in production with some of the lowest development costs in the industry and highest realized pricing and margins among our peers.

Even though we've reduced the budget by 23% versus last year, we remain the most active operator in Appalachia and have what we believe is the most fully integrated business model in the region through our attractive firm transport portfolio, our midstream focus, our significant hedge book and our tremendous inventory of drilling locations in two of the lowest-cost shale plays in North America.

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

Our first question will come from Holly Stewart of Scotia Howard Weil. Please go ahead..

Good morning, gentlemen..

Good morning, Holly..

First question maybe for Glen, just is the balance sheet and financing has been such a relevant topic in this commodity environment. You've outlined the budget. It looks like you'll have a bit of an outspend, but obviously ample capacity on the revolver to handle it.

But there is some funds drawn, so any thoughts on other ways of financing for this year?.

Yeah, Holly, we don't have any plans to issue equity in the near-term. I think the exception to that would be if we do participate in some of the consolidation that we think will happen in the Appalachian basin over the course of the year. That would be the exception where we may consider issuing equity.

But otherwise we just plan to draw on the revolver for the time being..

Okay, great.

And then maybe more topical for today with the announcement of Mariner East II being delayed, you began recovering some methane this quarter, any maybe thoughts or shifts in strategy with that pipeline being pushed out?.

Holly, I think we're supporters of Mariner East, of course, and see that that project is going to be strategic for us. I think we'll continue to just maximize our netbacks within the pool. We are considering some alternative projects as well to also move our NGLs to export markets, so we'll keep those in mind.

But it's really, stay in the Appalachian pool as well as transport out of the pool to maximize net returns to different destinations, whether it's Midwest or towards the Gulf..

Okay. Great.

And then maybe last one for me, Glen, any thoughts around the upcoming borrowing base redetermination period?.

We are quite positive on that. You know as in quarters gone by given the hedge book that we continue to add to in the out years and the pricing relative to the bank price deck in addition to the PDPs that we add each quarter, we foresee a positive outlook there on the borrowing base.

We'd expect to see actually an increase in the borrowing base in the spring determination for us. I don't think we'll ask for additional lender commitments but the borrowing base may go up. So we feel pretty good about that spring season for us..

Okay. Great. Thanks, guys.

Thank you..

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

Good morning. I wanted to ask you about the debates that's kind of been brewing in earnings season regarding the appropriate well spacing in the Utica to get the optimal drainage.

Was wondering where you stand and perhaps, if you could comment on that?.

Where we stand, we have done pilots on 750, 1,000 foot and even 500 foot in a lateral distance. We see that as long as we're drilling the wells at the same time that 750s worked quite well. I will say in the Utica all of our reserve bookings are more conservative they are all on 1,000 foot inter-lateral.

So we continue to watch but right now our economics would say, 750s work as well as 1,000s and in a PV world, they're as good if not a little bit stronger, we will continue to watch that.

But your inventory is on a 1,000 foot basis?.

That's right.

Okay. And my follow-up question just on the marketing expense, it picked up in Q4 but you highlighted how that should trend down as we think about 2016. I was wondering about your longer-term thoughts regarding marketing expense in an environment where takeaway should get better from an industry perspective and the industry is slowing down as a whole.

How do you think that should trend over the next couple of years?.

Well, there is still positive spreads if you look at the futures market. There's plenty of spread there over the next few years to capture in terms of mitigating our marketing expense, which we've been doing in the past and continue to do.

So we feel good about that and I agree the trend is to flatten out a bit in terms of supply but some pipes I think we'll get delayed as well. So it's a very dynamic equation. We due to our hedge position can continue to grow pretty rapidly. So we will fill up our capacity over time.

So it does go away for us at some point, so it's not a real long-term issue in terms of needing spreads for five years, ten years out there. It's really just the next few years and that looks pretty good, right now..

Okay. And just my final question just maybe some of your thoughts on the gas macro. We did see a smaller draw today than expected but I just wondered if you could maybe comment.

Obviously you've seen a real sharp pullback in activity in the Appalachian Basin, there are a lot of ducks but maybe your views just on gas over the next 12 to 18 months?.

Well, of course, we like the rest of the industry are watching those variables.

We are looking at, we follow, of course, rig count and local production as well as nationwide production and but I do think one of those variables that a lot of people struggle with because it's a bit of an unknown is how many ducks and what are the company's plans in completing those ducks? So that's a little bit of the X factor, the variable that's hard to fill in.

But we do see very dramatic drop-off in rig activity in Appalachia, and so we're all watching for the rollover and the flattening if not the decline. So, those are our views. Watching it carefully and there is still going to be more production than we'd all like in the near-term but over time it will work itself out.

It's definitely – just as across the world the weaker countries are going to fall back on oil and gas production, particularly oil just because the projects don't cut it at these prices I think you will see the same thing in microcosm in North America that we can all see the rigs dropping preferentially in the weakest plays and so it will be where the lowest cost structure is that the activity can continue and that's where we are..

Okay, thanks. Very helpful, thanks..

Our next question will come from James Sullivan of Alembic Global Advisors. Please go ahead..

Hi, good morning, guys. Thanks for taking the questions. My quick one I just want to go to the FT here and I recognize this is your FTPs on your general corporate presentation on page 37 is a graphical one, but I think it's a piece of ANR that comes out of service or comes out of your FT stack partway through 2016.

Can you just give me a little color on that and when it comes back in in 2017 is it the same demand charge on that piece of pipe?.

Yes. So part of our agreement with Energy Transfer as we signed on to the Rover project was that Energy Transfer takes over the ANR piece beginning July 1 and holds it until Rover is complete to our Seneca location, and so we project that to be about a year. As we see it now, the tariff will remain the same when we take back the ANR capacity.

There is an ANR rate case out there and so we will see how that is worked out to possibly increase the tariff by a little bit. We do see right now the spreads are not there on the ANR south piece very strong spreads on ANR north to Chicago and Michigan (37:01) but to the south the spreads aren't there.

The question will be what will it look like in a couple of years what will flood that area with gas in the Midwest that will need to get to the gulf. It will be the REX new capacity that drops off in places like Shelbyville. It will be the Rover capacity that drops off gas at Defiance and it will be the lack of pipe that goes into Chicago.

So we could see there can be a pretty strong buildup of gas in the Midwest that will need to find its way to the south and so we project that those spreads could go positive on ANR within the next year or two..

Okay, great. Thank you. That's a lot of great color and also thank you guys on the incremental FT and marketing disclosure that was really very helpful.

The second question I had was you guys have talked in your prepared remarks and I think you even talked about in the budget disclosure or budget release a week ago or so about expiring drilling and completion crews if you compare the rates you guys are paying which are obviously longer term contracted legacy rates.

You compare them to today's rates there's something like I think it was 10% or 12% of potential cost savings that you guys could capture and that was going into 2017.

Is there any appetite on your part or have you thought about approaching them and trading term for a little bit closer to market pricing, which would basically just be to kind of accelerate marking to market your service rates?.

Yeah. There is definitely those kinds of discussions that are underway..

Okay. Great. And if I could just squeeze one more in here? I just – today, the Mariner East delay notwithstanding, I know you guys obviously have the option on the Mariner East front for the propane and butane to take yourselves up to 112 Mboe a day.

But can you comment at all on your interest in the capacity expansion? The East II expansion that's been bandied about – have you guys looked at that? What's your take on it, and what's your sense of the risk of putting too much uncontracted U.S.

light feed into the European pet cam market? Is there any sense in which the market has its own decelerators in terms of demand, things like co-product production and whatever that might retard demand for U.S.

imports coming from the U.S.?.

Yeah. Those are certainly good questions and good considerations. As you're aware, we do have the right to double or there are increments that don't lead up to quite a doubling of 50,000 barrels a day on Mariner East. But certainly, there is available capacity or there would be available capacity on Mariner East.

And so, I think discussions are underway and one can incrementalize, one can do shorter-term deals, one can do interruptible. So, there is a lot of flexibility there. We're looking at the arb. Of course, we watch it all the time on the arb to northwest Europe and Far East, and those have been positive lately.

And you followed the shipping costs and how that's going down dramatically. So we do see the potential there, but you're right. There can be dynamics. There can be upsets in the world markets where for some period of time, whether it's months out of a year, that that can go negative.

So, we're definitely cognizant of that, and we'll be keeping that in mind as we consider whether to enter into more firm commitments or do it on a more interruptible basis..

Okay, guys. Thanks very much for the complete answers. I appreciate it..

Thank you..

Our next question will come from Jeoffrey Lambujon of Tudor, Pickering, Holt & Company. Please go ahead..

Thanks. Good morning. First, just a few follow-ups on some of the earlier questions.

On Mariner East II, could you talk more about the alternatives that you're assessing, just given the industry shift, the dry gas drilling and really the significant drop-off overall in the industry, as you mentioned? I'm just curious about what the opportunity set looks like and how you see that changing kind of in the near term?.

Yeah. I think those are still confidential projects that are going in different directions. So, there's a host of operators that are sponsoring those, going pretty much in most compass directions out of Appalachia. So, we have discussions underway. They look like valid projects.

But until the operators themselves or the project developers announce it, we'll keep it confidential..

Fair enough.

And then one more clarification on the spacing comments from earlier is that – the 750 foot that you feel comfortable with – is that more respective to the wet gas window? I know you're kind of earlier days for the dry gas drilling, but wondering if is meant to kind of apply across the portfolio or again, more specific to the wet gas?.

I'd say where we've done most of our drilling is right on that transition. So, that's where we've seen our results that my comments are on is in the 1,150 to 1,250 range. So, not in the deeply rich gas and so those would be the comments there and looking on the map right here, that's about the right BTU range 1,150 to even 1,225.

So there, we certainly run our economics and our returns and 750 foot works well for us. And there are trade-offs, but that's what we see as the best answer at this point.

We haven't gone as far down dip in Ohio as many of the other operators, so whether 750 or 1,000 is appropriate as you go further east – not sure – we'll have to judge for ourselves..

But we are booked on the 1,000 foot inter-lateral in terms of our feet..

Right. Right..

Understood. And then one last one from me just on Rover. Obviously, another pipe that the industry continues to focus on.

Just given the financial distress in the Northeast right now, how do you think about that capacity and the build out and the timing going forward? And for you guys specifically, do you see benefits of that potentially sliding to the right further, just given your portfolio of ample capacity on other lines?.

Well, Rover right now is – we project it to come to be operational to Seneca and the Utica by mid-2017 – and so far, they are on track for that. As you may be aware, the draft EIS was issued the other day.

So, as you step forward with the expected waiting periods between now and when construction could begin in the fall, it seems to still be on track operationally where it could happen by mid-2017. First of all, what if it doesn't, what if it's delayed? Then we'd have a lot of flexibility to shift capital more preferentially over to the Marcellus.

We have some good takeaway projects there that we can take advantage of. So, we have good flexibility there. Then, as far as delays and whether it can help some folks, it's possible we still have plans to fill that Rover capacity ourselves pretty quickly out of the Utica once it becomes operational.

Within the first year, we'll have filled up our Rover capacity. It can bode well if there is more open space that could be discounted by others for us to go beyond our contracted capacity, so it could be an advantage for us longer term..

Thanks for the detail..

Our next question will come from the line of Kevin MacCurdy of Heikkinen Energy. Please go ahead..

Hey guys.

Given the lower level of completions in 2016, will you guys run into any minimum volume commitments from the water business?.

Yeah. We will likely have some MBC payments in I believe in the $10 million to $15 million range for this year is the forecast. So, it's not terribly material.

Okay.

And just one more, does your 2016 land budget include any additional acreage or is that just to maintain current acreage?.

It's additional acreage. We picked up 29,000 net acres this last year and we expect to be continuing our success in base leasing through our trend it's both infill and extension. And so that's what the dollars are targeted towards..

Okay, thanks guys.

Thanks..

Thank you.

Ladies and gentlemen, this will conclude our question-and-answer session. I would like to turn the conference back over to Mr. Mike Kennedy for any closing remarks..

Thanks for participating on our conference call today. If you have any further questions please feel free to contact us. Thanks again..

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