Antero Resources Corp (AR) 2014 Q3 法說會逐字稿

Good morning. And welcome to the Antero Resources third-quarter 2014 earnings conference call. All participants will be in a listen-only mode.

(Operator Instructions)

Please also note, this event is being recorded. I would now like to turn the conference over to Michael Kennedy, VP of Finance. Please go ahead.

Thank you for joining us for Antero's third-quarter 2013 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 and A. I would like to direct you to the home page of our website at www.anteroresources.com where we have provided a separate earnings call presentation that will be reviewed in today's call. These materials along with the updated Company presentation can be located on the home page of our website.

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.

Thanks, Mike. Thank you to everyone for joining us. In my comments I'm going to highlight the recently priced IPO of our Midstream business, AM, provide a review of third-quarter price realizations and expectations going forward and cover our third-quarter financial results. Paul will then review our firm transportation portfolio including all-in costs and utilization numbers, operational results for the quarter as well.

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 the home page of our website that was just now uploaded in the last few minutes. Third quarter, 2014 earnings call presentation. This is separate from our monthly investor presentation also located on the website. So please make sure you're reviewing the correct slide deck during the call.

As you are probably aware, we successfully priced the IPO of our Midstream business, Antero Midstream Partners LP, earlier this week. The common units of Antero Midstream trade on the New York Stock Exchange under the symbol AM. It was a great outcome for us and the market response was tremendous.

Turning you to page 1 of the earnings release that I just referred to, the presentation on the website. Page 1 is entitled Successful Midstream IPO. AM priced at $25 per unit -- or 25% above the midpoint of the $19 to $21 range, so great reception there. That resulted in a 2.72% IPO yield on the distributions. And that is based on a minimum quarterly distribution of $0.68 per unit. The closing price of Antero Midstream on its first day of trading which was yesterday, closed with the market value, enterprise value of about $4 billion including the $250 million of cash proceeds that will be retained at the general partnership for general corporate purposes.

Now looking at slide number 2 entitled Antero AM IPO Compared to Other IPOs. You'll see that the AM IPO represented the largest LP MLP IPO ever and the lowest yielding IPO ever. You can see that at the bottom and the top of the chart there. Gross proceeds at the bottom; distribution yield at the top.

Previously on page 1, a couple things to point out. The following range value was about $2.8 billion. The trading range as the close yesterday, as I mentioned, $4 billion. That traded with a 2.4% yield. We're excited to get AM out there in public as it unlocked incremental value previously held at AR, at the parent. The IPO resulted in net proceeds to Antero of about $700 million. Those will be upstreamed at the closing next week. The Midstream assets initially held by AM including gathering and compression assets, while the fresh water distribution business was retained at Antero, subject to an option on behalf of AM to potentially acquire these assets at a later date.

As you can see on the chart on page 1, the water system stays up as a sub of Antero Resources, as, of course, do the upstream assets and then Antero owns pre-exercise of issue, the [green shoe], 74% of the limited partnership interest of Antero Midstream. And then you can see the market cap of Antero Midstream at the bottom left of that page. $4.3 billion. The IPO of AM will enable us to take on even more Midstream projects in the Marcellus and Utica as AM will be self-funding going forward. At closing next week, AM will have $250 million of cash on the balance sheet and a fully undrawn $1 billion credit facility and that is supported by 17 banks. As of September 30, 2014, and adjusted for the lender commitment and borrowing base increase announced last month, as well as the AM IPO proceeds, we have approximately $800 million drawn under the AR credit facility.

From a liquidity standpoint, we have approximately $1.9 billion of committed availability under our revolver and about $2.9 billion of unused borrowing capacity. In addition to that, we have over $1 billion of additional liquidity available at AM to fund Midstream growth. I want to remind you that there was no impact to our third quarter results as the IPO did not price until November 4, and does not close until November 10 next week. Beginning next quarter our AR results will include the results of AM on a consolidated basis.

Now on to price realizations. I will refer you to slide number 3 that's entitled 3Q 2014 Realizations. During the quarter where we saw yet another quarterly average production record of approximately 1.1 BCFE per day, we sold 59% of our gas at favorably priced indices which included TCO, NYMEX and Chicago. You can see those at the top of the page, the first three line items. The remaining 41% of our gas was sold at Dominion South and TETCO which have experienced significant declines in price throughout the year due to oversupply versus pipeline takeaway.

This mix of sales point resulted in a negative differential in NYMEX for the quarter of $0.43. If you combine the average differential number in that table, negative $0.84 with the BTU upgrade of $0.41, that's $0.43 negative differential. That's before the affect of cash-settled hedges. We had natural gas cash-settled hedge gains for the quarter of $0.68 per MCF including $38 million in gains at Dominion South Index; $19 million at the TCO Index; and $1 million in gains at NYMEX. Including these hedge gains, our realized natural gas price was $4.31 which you can see upper right on that page or a 25% premium to NYMEX during the quarter.

Our realized natural gas 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 firm transportation accessing favorable markets. You can see that bottom left in the chart, the $4.31 leading the Appalachian group there. As a reminder, we're located in the southern portion of the Marcellus so our local index is TCO, which is the highest priced index in the basin. Coupling our realized gas prices after hedges with our liquids production resulted in a top line all-in price realization on a gas equivalent basis of $4.96 per Mcfe for the quarter.

As you can see on slide 4 -- page 4, titled Biggest Bang For The Buck, this top line realization is nearly $0.50 higher than our closest Marcellus peer. In addition to our all-in price realizations, I'll also point out that we continue to lead the way from an EBITDAX margin standpoint. $2.93 per Mcfe. You can see that in the highlighted box next to the AR stacked bar there. When comparing the EBITDAX margin against our $0.58 per Mcfe of finding and development costs are less than $1 on a bottoms-up development cost depending on how you want to look at it. You can easily see that our projects continue to generate high rates of return in the current gas and oil price environment. Staying with price realizations, I would now like to look forward and discuss expected realizations but also expand further on the components responsible for driving our peer leading price and margin position.

So turn to slide 5. That's titled Antero Realized Price Road Map. We cover in detail all the aspects that contribute to our best in class per Mcfe price realizations, including the following. Our firm transport portfolio delivering our gas into favorable pricing markets. Number two, our hedge portfolio insulating a majority of the remaining residue gas forecasted to settle at less favorable market hubs. The price uptick, number three, associated with currently rejecting ethane at Sherwood and Seneca processing facilities and pricing the ethane in the residue gas stream at BTU value.

Number four, the value associated with our C3-plus NGL barrels being recovered at those same facilities along with our well-head condensate barrels. Covering firm transportation first, on slide number 5, you'll note that in the fourth quarter, we expect to increase -- an increase in the percentage of gas sold to favorable markets to 65%, and that's compared to the 59% in the third quarter. This is due to a combination of higher expected fourth quarter Utica production volumes that are able to access the Chicago market through Rockies Express and the addition of an incremental 160,000 MBT per day of TCO firm transportation at the beginning of this month that increased our TCO market access to a total of 580,000 MMBtu per day in the Marcellus.

In 2015, we forecast that we will sell approximately 68% of our residue gas to favorable market indices, and you can see that in red across the top of the page there with the arrows. With the increase we'll be driven primarily by an increase in our Utica production that will be sold into the Chicago market. In 2016, we are projecting a further increase in the percentage of our gas sales that will be sold into favorable indices to 84%, as you can see in red on top there, of our total residue gas sales, with increase attributable to the expected completion of a regional gathering project giving us access to our 590,000 MMBtu per day of firm capacity on TGP which increases our exposure to Gulf Coast pricing.

Secondly, regarding the hedges, you'll see that of the remaining 35% of Q4, 2014 residue gas production going to less favorable markets, 160,000 MMBtu per day or approximately 45%, is hedged at the Dominion South Index of average price of $5.27. You can see that just to the right of the stack bar under the fourth quarter there. Dominion South is currently trading at $2.65 per MMBtu so you can see the value in these hedges. In 2015, 31% of our forecasted residue settlements will be at less favorable indices and approximately 60% of those sales are hedged to Dominion South at an average price of $5.60 per MMBtu. So once again, you can see that to the right of that middle bar under 2015.

Finally approximately 96% of 2016 forecasted residue settlements at less than favorable pricing are hedged at Dominion South at an average price of $5.35. Based on current future prices, we would expect to realize hedge gains of approximately $0.68, $0.59 and $0.38 per Mcf for Q4 2014, calendar 2015 and 2016 respectively.

Moving down the table to cover the third component BTU upgrade. Because we reject ethane at Sherwood and Utica processing facilities, our residue heating value is approximately 1100 BTU at the plant tailgates. This results in approximately a 10% uplift in gas price realizations for our processed gas contributing over $0.30 per Mcf of price uptick forecasted for Q4, 2014 through 2016. You can see that I am referring to the table at the bottom of the page.

Lastly, propane, butane and heavier products recovered at the processing plants along with the condensate recovered at the well-head provide yet another incremental value impact to price realizations. Because our NGL barrel is currently C3-plus, and therefore does not contain any ethane, we receive very attractive per barrel pricing. During the quarter, we received just under $47 per barrel net of higher seasonal differentials attributable to warm weather which represents 48% of the average third quarter WTI price.

When referring to the first nine months of the year for 2014, our NGL realized price averaged 53% of WTI. You see some seasonality in those numbers throughout the year, but we have averaged 53% for the first nine months of the year within our forecast range of 53% to 57%. Additionally, we received approximately $84.17 per barrel before hedges for our condensate barrels.

Liquids production represented 14% of total third-quarter volume and combined with attractive prices received for our condensate and NGL barrels resulted in liquids contributing 28% of this quarter's total product revenues. Another record for Antero. We expect these proportions to continue to increase over the coming quarters and years which will further enhance our all-in price realizations. We're forecasting a $0.59 per Mcfe liquids impacter in the fourth quarter of this year and expect a slightly higher trend for both 2015 and 2016 based on current prices due to the growing volumes of liquids proportionately.

To summarize this slide, based on our current strip pricing and the factors I have covered, we forecast that we'll realize all-in prices in excess of $1.00 per Mcfe above NYMEX pricing through 2016. So looking at the next 2.25 years. In other words, we estimate that high $3 NYMEX gas prices translate into around $5 per Mcfe all-in realized prices for us over the next 2.25 quarter years.

Rounding out the quarterly financial results, let's move to the income statement. Revenue for the third quarter was $762 million as compared to $385 million for the third quarter of 2013. Adjusting for noncash items including $252 million in noncash gains on unsettled hedges, adjusted net revenue increased 90% from the prior-year quarter to $511 million. From a cash operating cost perspective, production expenses were $1.60 per Mcfe.

As a reminder, our production expenses include lease operating, gathering, compression, processing, transportation, production tax and exclude marketing revenues and expenses. The increase in cash operating costs were driven by increased higher cost liquids production as we've ramped up our processed volumes.

Our G&A expense for the quarter was an attractive $0.29 per Mcfe excluding noncash stock compensation expense. EBITDAX for the third quarter was $292 million. That's 59% higher than last year. And lastly for the quarter, we reported net income of $204 million or $0.78 per share which represents a 73% increase over the prior year. Adjusted net income was $72 million, a 47% increase over the prior year.

Before I turn it over to Paul to cover our firm transportation portfolio and our operational results, I would like to summarize the quarter and year-to-date results from a financial perspective. We are well capitalized and continue to achieve tremendous growth with natural gas industry leading price realizations, peer leading cash margins and returns with strong visibility that these results will continue well into the future.

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

Thanks, Glen. In my comments today I'm going to address our firm transport strategy including its low-cost nature and our expected utilization of the portfolio we have assembled as well as to give an operational update.

Let me start with firm transportation. We have an industry-leading portfolio of firm gas and NGL takeaway which is detailed on slide number 6 on the web, and that is entitled Largest Portfolio Of Firm Processing And Gas And NGL Takeaway In Appalachia. We made additions to our natural gas FT portfolio during the third quarter of 2014 resulting in an Appalachian E&P industry-leading 4 BCF a day of firm transportation and sales. To complement our Gulf Coast directed firm transport, we have entered into an agreement to sell 200,000 MMBtu a day of natural gas at NYMEX-based pricing to Cheniere at Sabine Pass for LNG export.

From a liquids perspective, as reported in our third quarter operations update, we've increased our commitment Sunoco's Mariner East 2 project from 51,500 barrels a day to 61,500 barrels per day. The 61,500 barrels per day consists of 11,500 barrels of ethane, 35,000 barrels of propane, and 15,000 barrels of butane. In conjunction with our ethane commitment, we executed an ethane export agreement for 11,500 barrels a day with Borealis that will begin once Mariner East 2 is in service.

You may have noticed that Sunoco announced today that it has reached final investment decision, FID, on Mariner East 2. So the project is committed and expected to be placed in service by the end of 2016. Additionally, we have committed 55,000 barrels a day of ethane to the two crackers that have been announced -- ethane crackers, announced by Odebrecht Braskem and Shell respectively which are currently pending final investment decision.

To focus on natural gas firm transport, let's go to slide number 7 titled Firm Transportation Reduces Appalachian Basis Exposure. This slide illustrates all-in low-cost nature of our portfolio that accesses currently favorable markets and diversifies our exposure to Appalachian pricing. Our firm transport will provide us the ability to direct 45% of our production to the Gulf Coast, 20% to Midwest pricing including Chicago and Detroit and 35% to Appalachia and the Atlantic Seaboard by 2016. The ability to direct our gas to the Gulf Coast is strategic as we expect the vast majority of growth in gas and NGL demand to occur on the Gulf Coast over the next five years.

And as you can see, our all-in firm transportation costs will increase from $0.28 per MMBtu this year to $0.46 per MMBtu in 2016, assuming full utilization and before the marketing and release of any excess capacity. It's important to point out that the utilization costs we're referencing on this slide include both the fixed charge to reserve the capacity, otherwise known as the demand fee, and the variable costs associated with flowing gas on the firm transportation, otherwise known as the commodity fee. Also worth mentioning is that the $0.18 per MMBtu increase in all-in costs over the next two years is more than offset by expected basis differential improvement of over $0.20 in MMBtu, which illustrates the importance of having low cost firm transport that delivers to premium-priced markets.

To further understand our expected utilization of this natural gas FT portfolio, let's move to slide 8 titled Antero Firm Transportation Appropriately Designed To Accommodate Growth which was also recently added to our monthly website presentation. As you can see from this slide, based on our net production targets of 45% to 50% growth in each of 2015 and 2016, we anticipate that we will use 75% to 80% of our firm transportation portfolio over this two-year period. Of the remaining 20% to 25% that is not utilized, we believe approximately 10% to 15% is highly marketable based on current differentials between the receipt and delivery points associated with the [confirmed] capacity.

As a result, we feel comfortable that we will be able to either release this capacity to other operators with less favorable sales point options or even generate positive marketing margins on purchased gas. The remaining 10% of our firm transportation portfolio, it relates to less favorable Appalachian indices based on current pricing may remain unutilized.

Having said that, you'll see from the last two lines of the slide that the cost of this unutilized and unmarketed portion of our firm transportation is immaterial, costing us only $0.02 to $0.03 per Mcfe of production. We designed our firm transportation portfolio in a very strategic manner in order to accommodate our significant future targeted growth and provide us with attractively priced and geographically diverse end markets.

Now, on to the operational update. Our net daily production for the third quarter of 2014 averaged a Company record 1,080 MMcfe a day -- 1,080 million cubic feet equivalent per day including over 25,000 barrels of liquids for 14% of total volumes. Third quarter 2014 production represents an annual organic production growth rate of 91% and a liquids production rate for the third quarter of 2014 represents an annual organic production growth rate of 217%.

With consistently strong well results in our Marcellus and Utica rich gas areas, we continue to deliver Appalachian E&P industry leading production growth with net production for the quarter exceeding 1 BCFE per day for the first time. As the most active driller in Appalachia today, we remain poised to deliver high growth and strong cash flow for the foreseeable future. Our third quarter 2014 production solidly positions us to meet our 2014 production guidance as well as our 45% to 50% growth targets for both 2015 and 2016.

In the Marcellus, we continue to be the most active operator with 15 rigs operating. Eight of these rigs are powered by either natural gas from our producing wells in the field or liquefied natural gas. We implemented a program about two years ago to convert drilling rigs to be able to run on either natural gas from the field or LNG in order to reduce emissions, realize fuel savings, and minimize diesel tanker truck traffic.

On the completion side, we have five dedicated completion crews and three spot completion crews currently working in West Virginia. We have also been utilizing the first clean fleet completion spread in the Marcellus since July, and the fleet has truly delivered excellent performance for us. In fact, we recently executed a contract for a second clean fleet completion spread with US well services and expect this fleet to be placed in operation during the second quarter of next year.

Clean fleets are powered entirely by natural gas which results in the replacement of diesel engines with electric motors run off of natural gas generators, which means cost savings, smaller physical and environmental footprints, reduced noise levels, and enhanced safety features. As it relates to our drilling activity in the Marcellus, we continue to utilize shorter stage lengths or SSL completions. Virtually all of our 93 horizontal Marcellus wells drilled and completed in 2014 utilized SSL completion techniques.

Of the 93 wells, 84 have been online for more than 30 days and had an average 30-day rate of 13 million cubic feet equivalent a day while rejecting ethane. The equivalent a day includes 14% liquids. The average lateral length for the 84 wells was approximately 7,900 feet. Production rates from SSL wells continue to exhibit 20% to 30% improvement as compared to the non-SSL type curve with average well costs only increasing approximately 10% to 15% when compared to the non-SSL wells.

In September, we placed online the four-well RJ Smith pad in our highly rich gas regime. The four wells had a combined peak 30-day sales rate of about 56 million cubic feet equivalent a day with a BTU content of 1,220 gas again in ethane rejection mode, 21% liquids. These are very strong 30-day rates, and our support of the continued transition of our development program into the more liquids rich areas of our Marcellus leasehold position utilizing SSL completions.

As we've shifted our activity in the Marcellus to the liquids rich gas areas, it's imperative that we have adequate processing capacity MarkWest just recently placed online Sherwood number 5 which is a 200 million cubic foot a day cryogenic processing facility at the Sherwood facility located in Doddridge county. This now gives us access to 950 million a day, cubic feet a day, of firm processing capacity in the Marcellus. As previously announced we have also committed to two additional 200 million a day cryogenic processing plants, Sherwood number 6 and number 7. Sherwood 6 is expected to go online in the second quarter of 2015 and Sherwood 7 is expected to go online in the third quarter of 2015. In total we have committed to 1.35 BCF a day of cryogenic processing capacity in the Marcellus.

Now shifting to the Utica. We are currently running seven rigs in the Utica and similar to the Marcellus, three of these rigs are being powered either by natural gas from the field or LNG. On the completion side, we have one full-time dedicated completion crew and one spot-completion crew working in the Utica. Since the beginning of the year, we have completed and placed online 30 wells in the Utica. Of these 30 wells, 25 have been online for more than 30 days and had an average 30-day rate of about 15 million cubic feet equivalent a day including 44% liquids.

The average lateral length for these 25 wells was approximately 7,600 feet. The first three wells on the four-well urban pad that were placed online in early October have an average BTU content of 1,187 and are currently averaging 65 million cubic feet equivalent a day on a combined basis in ethane rejection including 14% liquids. These wells represent our latest rich gas wells placed online in 2014 and we plan to complete nine additional wells located in the highly rich gas regime and two additional wells in the highly rich gas/condensate regime throughout the remainder of the year.

From a processing perspective, we have processed all our gas at the Seneca facility and have 450 million cubic feet a day of firm processing capacity that will increase to 800 million a day by 2016. Regarding capital expenditures for the quarter, we invested $621 million on development; $202 million on infrastructure projects including fresh water distribution services; $94 million of base leasing; and $185 million on a Utica acquisition.

Regarding land additions, our strategy is to leverage our strategic advantage of being the most active and sizable operator in the area by consolidating and blocking up our areas of operations. We added approximately 32,000 net acres in the core of the liquid rich Marcellus and the Utica Shale plays during the quarter for $279 million. Included in this acreage was a $185 million acquisition of approximately 12,000 net acres primarily in Noble county, Ohio in the core of the Utica Shale play. This Utica transaction resulted in the addition of approximately 80 new drilling locations and the increased working interest percentage and planned lateral lengths associated with 120 existing locations.

In total, the acquisition represents over 650 BCF equivalent of 3P reserves with an associated PV10 value of approximately $700 million assuming midyear 2014 SEC prices. In summary, we continue to 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 transportation portfolio, our Midstream focus, our significant hedge book and the liquids rich drilling focus. As we've stated previously, we continue to believe that we are well-positioned to achieve significant value creation with clear visibility to high production and reserve growth and peer leading per-unit margins for many years to come.

With that, operator, we are now ready to take questions.

Thank you.

(Operator Instructions)

Neil Diamond with SunTrust.

Good morning, guys. Good details. Glen or Paul, just how do you think about going into next year with a pricing environment? I guess it's a nice problem to have. When I look at capital allocation, sort of two questions here around that. One, would we see the mix between the Marcellus and the Utica potentially shift a bit next year based on returns you are seeing? And then secondly around allocation, obviously you are set up very well now with Midstream capacity. So is it safe to say on a percent basis, we'll see much more diluted or actually appropriated towards the upstream versus the Midstream?

Thanks, Neil. We're always considering shifting. That's the beauty of only being 50 miles apart between our two projects is that we're always looking at shifting a rig back and forth between those two projects just to optimize the very best locations. I don't think you'll see a wholesale shift back and forth with capital spending between the two projects. They are pretty well optimized right now but there might be a rig in one direction or another. Yes, we are having good results, and so I think Glen can cover our budget here. Go ahead, Glen, for CapEx.

Yes, Neil, thanks. I'll just point out that with this new Midstream vehicle, MLP, that's where all the Midstream CapEx is carried going forward. It's well-capitalized with over $1 billion of capacity there right out of the gate at the Midstream business. And so I think that certainly helps a lot. Liquidity now, if you included all the borrowing base that we have pro forma for all of this, as of September 30, liquidity is up around $4 billion. So great liquidity position and due to our hedges and increasing hedge position for 2015, we don't see any need to pull back on our capital budget as to what we're planning for the year. So we continue with our guidance of $2.3 billion to $2.5 billion for 2015 for drilling and completion CapEx.

That makes sense. And just lastly, just your thoughts on the Utica dry gas. Obviously, certainly, with you starting to enter there and some great peer results, just your thoughts as far as potentially increase in activity there?

Yes, you're right, Neil. The results of the dry down dip, we'd call it, deeper Utica dry gas play have been fairly spectacular. And the most recent tests come to within our acreage in northwestern West Virginia. We certainly like the looks of it.

We have got about 150,000 net acres that are right in that vicinity in the northwestern portion of our block, of course, have the deep rights for Utica. So it looks good. Can it compete for capital with our liquids? Time will tell.

We haven't seen the declines on the wells yet. But for the near term, we're just going to stay focused on liquids, but certainly have that in the back of our minds that we could add some development both on the upstream side with drilling. And on the Midstream side, it will need new infrastructure gathering and compression to lead into the takeaway points over time. It's probably going to be a little while before we shift en masse to the deep drilling of the Utica. I think we are talking years.

Certainly a nice optionality to have. Thank you all.

Yes, thank you.

Thank you.

The next question comes from Jeffrey Lamberjohn with Tudor, Pickering Holt and Company.

Good morning, guys. Just one from me on leasing going forward. Just wondering how you are thinking about that and how you are looking at budgeting for that next year?

Leasing, going forward, our focus, Jeffrey, is on the base leasing, so we have more than 850 lease brokers that are working every day for us, and they're doing things like setting up drilling units and so on but they're also working the records. That's where we obtain quite a lot of value is doing the base leasing that pulls all of our fragments together and builds them into drilling blocks.

Yes, Jeffrey, we see that land initiative continuing. We haven't come up with a budget yet for next year for land, but the momentum continues certainly in the core area and the rich gas core area.

Thank you.

Thank you.

(Operator Instructions)

The next question comes from Dan Guffey with Stifel. Please go ahead. Mr. Guffey, your line is now live.

Sorry about that, guys. Thanks for all the color today. You have been moving rigs into the liquids-rich portion of the Marcellus. I'm curious, across that acreage, is there a point where you're going to be forced to extract ethane because of the BTU content and pipeline restrictions? And if so, at what point or what time do you think that may happen?

Yes. Our models say that we don't see that in any time in the near term. Our gas is just at the right BTU that coming out of the plant, it comes out at about 1,100 BTU residue gas and that meets the spec requirements of the regional lines that our gas flows into. So we don't see ourselves in a must-recover situation.

We do have the opportunity or the right through MarkWest infrastructure to recover ethane if we need to. And if we did, we'd put that into our ethane capacity on ATEX that goes to Belleview. Right now the ATEX capacity is being sublet to others that are in the must-recover mode, but don't see ourselves being in must-recover for the foreseeable future.

Okay. Great. And then I'm curious just on well completion design, obviously 7,900-foot laterals, you guys continue to drill some of the longest wells in the basin and then also you've incorporated SSL completion pretty much across the board.

Wondering what else you guys are doing to increase deficiencies, what else you guys are testing and if you see any upside from the current type [curbs] that you guys have published.

I have said this before, but I don't think you ever reach perfection in completion design. Our folks -- they're not changing every single frac or every single well, but every six months or so, there might be a little tweaking that seems to improve things, so we'll see on the completion side what more can be added. Our standard SSL is 200 feet stage length in the Marcellus. We've piloted some 150s and we'll see how that does over time.

Okay. Thanks for all the color, guys.

Thank you.

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

I want to thank everyone for participating in our conference 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 your lines.