Antero Resources Corp (AR) 2014 Q4 法說會逐字稿

Good day, and welcome to the Antero Resources year end 2014 earnings conference call and webcast. All participants will be in a listen only mode.

(Operator Instructions)

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

Thank you for joining us for Antero's fourth-quarter 2014 investor conference call. We'll 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 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 homepage of our website.

Before we start our comments, I would first like to remind you that during this call Antero management will make forward-looking statements. Such statements are based on 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 the recently released 2015 capital budget and guidance, provide a review provide a review of fourth-quarter price realizations and expectations going forward, including our substantial hedge portfolio, and cover fourth-quarter financial results. Paul will then review our 2014 development program by highlighting our low F&D cost and significant resource base, briefly discuss service cost in the current commodity price environment and summaries operational results for the quarter.

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 entitled Fourth-Quarter 2014 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.

Before we get into today's topics, I just wanted to briefly revisit Antero midstream IPO that happened in November of 2014 just a few months ago. This was a very strategic transaction for us as it generated $1.1 billion in total net proceeds, with $843 million of those proceeds pushed up to AR, to Antero Resources, and $250 million remaining as cash on the balance sheet for AM. Obviously a significant deleveraging event for us. The IPO was also instrumental in unlocking incremental value previously held at AR. As of yesterday's close, AM's equity value of $3.9 billion implies a $10 per share value associated with AR's 70% ownership in AM. Additionally, the AM IPO will enable us to take on even more midstream projects in the Marcellus and Utica since AM will be self funding going forward.

Now on to our prepared comments. As you are probably aware, about six years ago, we identified the Appalachian basin as potentially the lowest-cost natural gas basin in North America. This fact has been borne out over time, so we focused all of our efforts to acquire acreage and develop this area through the drill bit.

Our thesis was that you need to be in the lowest unit cost area with a meaningful acreage footprint in order to generate attractive rates of return and have a sustainable development program through all commodity price environments. So, although we have announced a 40% reduced budget in 2015, we still plan on running an average of 14 rigs and completing 130 wells that will generate 30% to 50% rate of returns in the current price environment as we deliver 40% annual production growth. It's taken us about 1.4 Bcfe per day net. The 40% year-over-year reduction in capital, along with the 40% growth, or the 40/40 plan that we call internally, is a testament to increasing productivity and capital efficiency in our development program.

You might ask, why reduce the budget at all with the attractive rates of return and substantial growth? Well, the budget process for this year was quite dynamic, as you can imagine, as we were continually rightsizing for changing price scenarios. Our final conclusion was that while our wells still generate attractive rates of return an low commodity prices, the payouts from the wells lengthened from approximately a year or two, out to two or three years. That's adding more leverage to the balance sheet in the near term. The increased leverage would in turn reduce our flexibility to capitalize on potential opportunities during the year. With that being said, we wanted to maintain optionality around accelerating the development program if prices improve. So, we will continue to run the most active program in Appalachia with an average of 14 rigs drilling during the year, about 180 wells, while only completing 130 of these wells. That will provide us with a substantial inventory of wells that can be completed in 2016 should prices improve.

Slide number 1 of today's earnings call presentation is titled Completion Deferrals Operational Flexibility. It adds some perspective to this inventory. Our average 30-day production rate in the Marcellus is a bit over $13 million a day equivalent per well in 2014. That's the 30-day rate. If we decide to complete those wells in addition to our traditional activity, we could bring on almost $400 million a day equivalent of gross wellhead production in a matter of months. And this is from the 50 wells that we have deferred into 2016. This inventory provides tremendous optionality and allows us to accelerate our growth in 2016, if warranted by commodity prices. One last item to note on slide 1 related to the deferred completions is the timing of the referrals will be and the second and third quarter of this year, 2015.

This timing was designed to limit our exposure to Dominion South and Tetco M2 pricing during the summer months of the year. Our firm transportation portfolio to TCO in the Marcellus is fully utilized until the fourth quarter of 2015 when we are scheduled to gain access to a regional gathering pipeline which will result in NYMEX and TCO-based pricing going forward as we access additional markets. The strategy of wanting to bring on wells when this capacity is available results in higher well economics, or about an 18% improvement on IRRs, despite the present value impact of the deferrals. To summarize or 2014 budget, we plan on reducing our capital by 40% while generating organic growth of 40% as well and maintaining optionality for acceleration in 2016.

Now, on to price realizations. I will refer you to slide number 2 titled Highest Realizations in Margins Among Large Cap Appalachian Peers. During the quarter, we saw yet another quarterly average production record for Antero of 1.265 Bcfe per day net and sold 64% of our gas at favorably priced indices that included to TCO, NYMEX and Chicago. The remaining 36% of our gas was sold to Dominion South and Tetco, which experienced significant price discounts to NYMEX throughout the year due to oversupply versus pipeline takeaway. This mix of sales points resulted in a negative differential in NYMEX for the quarter of $0.34 per annum after Btu upgrade and before the effect of cash settled hedges.

We had natural gas settled hedge gains for the quarter of $0.73 per Mcf, including $43 million in gains at Dominion South, $25 million in gains at the TCO index and $6 million in gains at NYMEX Henry Hub. Including these hedge gains, our realized natural gas price was $4.39 per Mcf, or a $0.39 premium to NYMEX during the quarter. 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 transportation accessing favorable markets.

As a reminder, we're located in the southern portion of Marcellus where our local index is TCO, which is the highest price index in the basin, by the way. Coupling our realized gas price after hedges with our liquids production and $0.09 per Mcfe of contribution from third party midstream revenues results in a top line all-in price realization of $4.77 for Mcfe for the quarter. As you can also see on slide 2, this top line realization is $0.62 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 at $2.84 per Mcfe. When comparing this EBITDAX margin against our $0.61 per Mcfe of finding and development costs or our less than $1 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 at high recycle ratios in the current gas and oil price environment.

Another important item to highlight in today's commodity price environment is the hedge portfolio. It is detailed on slide number 3 titled Largest Gas Hedge Position in US E&P and Strong Financial Liquidity. We have one of the largest hedge positions in the industry with 94% of 2015 production hedged, including approximately 100% of our projected oil and propane production hedged. As you may recall, in our 2015 guidance release we provided EBITDAX sensitivities to commodity price changes to illustrate the impact of our 2015 hedge position. For every $0.50 per Mcf move in natural gas, AR's EBITDAX changes by less than $1 million. On the liquids side, for every $10 per barrel move in WTI, and taking NGLs with it, AR's EBITDAX changes by $30 million. At year-end 2014, with 1.8 Tcfe hedged with a $1.6 billion mark to market value.

An additional item highlighted on slide 3 is our liquidity position. We recently completed our 2015 spring redetermination process with our borrowing base reaffirmed at $4 billion and increased the banking commitment to $4 billion as well. So, the banking lender commitments went up by $1 billion from $3 billion previously to $4 billion now. There are two attributes required to maintain the borrowing base in a declining commodity price environment, and that is significant PDP reserve growth and a strong hedge book; Antero has both of those. The increase in banking commitments results in AR liquidity in excess of $1.9 billion, which is more than adequate for the foreseeable future. Additionally, when you include AM liquidity of $1.2 billion at year-end 2014, we've got total consolidated liquidity over $3 billion today.

Rounding out my comments today, let's touch on quarterly financial results. Adjusted net revenue increased 78% from the prior year quarter to $585 million. Per unit production expenses were $1.54 per Mcfe. As a reminder, our production expenses include lease operating expense, gathering, compression processing, and transportation as well as production tax. Our G&A expense for the quarter was at an attractive $0.24 per Mcfe, excluding non-cash stock compensation expense. EBITDAX for the fourth quarter was $330 million, 53% higher than last year. And lastly for the quarter, we reported adjusted net income of $78 million, or $0.30 per share, a 6% increase over the prior year despite the approximate 10% decline in gas prices and 30% decline in oil prices.

Before you turn it over to Paul to cover our development program 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 will turn the call over to Paul for his comments.

Thanks, Glen. In my comments today, I'm going to review our 2014 development program, highligting our significant resource base and its low department cost nature. I'll provide a brief update on service costs and discuss operational results for the quarter.

We executed our 2014 development program ahead of plan, as production and reserve ads were both excellent. Our production for 2014 averaged 1.007 Bcfe per day, which was in excess of our original guidance of 950 million cubic feet equivalent per day and slightly above the increased guidance of 1.0 Bcfe per day. Our proved reserves also were ahead of expectations as SSL completions improved our recoveries. The most important development of 2014 was the validation of SSL completions in the highly rich gas areas of the Marcellus where we had limited development prior to this last year. This is especially important in low gas price environments as the liquids drive well economics, even with low oil and NGL prices.

As shown on slide 4 titled Marcellus Development Program Target the Liquids, the success of our 2014 liquids development program has carried forward into the 2015 development plan. And we are forecasting the completion of 80 liquids-rich locations that have an average heating content of 1,250 Btu. The 2015 drilling program is shown in red on the slide. The impact of the 2014 development program can also be seen in our outstanding reserve growth for the year. Our proved reserves grew 66% during the year to 12.7 Tcf equivalent, and only 29% of our total 543,000 net acres have proved reserves associated with it at year-end 2014, so we have a lot of growth ahead of us in proved reserves. All sources finding and development costs, including acreage costs, were $0.61 per Mcfe, and we had bottoms-up well by well development costs of $0.98 per Mcfe. These represent some of the lowest costs in the industry, and when compared to the $3.16 per Mcfe EBITDAX margin we generated during the full year, this generates best in class recycle ratios.

To reiterate Glen's earlier point, we came to Appalachia and have solely focused on our efforts here with the principal tenant in our strategy being to gain access to the lowest unit cost structure for the development of hydrocarbons. The Marcellus shale accounted for 94% of our proved reserve volumes with the remainder attributed to the Utica shale. Excluding production, we were able to add 5.0 Tcf equivalent to proved reserves to increase the total proved reserves to 11.9 Tcfe in the Marcellus this year, and importantly, of that 11.9 Tcfe overall in the Marcellus, 3.4 Tcfe, or 28% of that total, was in the proved developed category, as we converted 135 wells in the Marcellus to PDP during the year. In the Utica shale, we have only classified approximately 758 Bcfe as proved reserves across our core leasehold position of 143,000 net acres. We have 64 proved developed locations, but only have 42 proved undeveloped locations as of year-end. So, this is quite conservative from a reserve categorization standpoint.

We are focusing on our efforts in the Utica shale for 2015 on our rich gas areas which provides the highest rates of return across our entire portfolio. Please look at slide 5 entitled Utica Development Program Target the Rich Gas Regimes, and that slide shows that similar to the Marcellus, we plan to focus on liquids-rich locations in both the highly rich gas and the rich gas regimes which represent the highest rates of return in the current commodity price environment. We are forecasting the completion of 50 liquids-rich locations in 2015 that have an average heating content of 1,200 Btu. These are highly productive wells with rates of return above 40%, even in today's prices.

Based on Antero's successful drilling results to date, as well as those of other operators in the vicinity of Antero's leasehold, the Company believes that a substantial portion of its Marcellus and Utica shale acreage will be added to reserves over time as more wells are drilled. However, due to SEC requirements, we have classified the vast majority, approximately 88% of that acreage, as probable or possible reserves. We had year end 3P reserves across the Company of 40.7 Tcfe, which is a 16% increase over year end 2013 3P reserves of 35.0 Tcfe. The 16% increase in 3P reserves was driven by the addition of 50,000 net acres in the core rich gas Marcellus and 43,000 net acre addition in the core Utica in 2014, and also the transition of our entire development program to SSL completions. We were able to convert approximately 68% of our 3P undeveloped locations to the SSL type curve in the Marcellus, but with continued success, you should see that percentage probably increase to close to 100% type curve using SSL 100% of the Marcellus.

The Marcellus comprised approximately 70% of our 3P reserves as it had 28.4 Tcfe at year-end 2014. Importantly, 96% of Antero's 28.4 Tcfe of 3P reserves in the Marcellus were classified as proved and probable. That's 2P, so 96% of our 3P reserves is really 2P, reflecting the delineation work we and the rest of industry have performed and thus, the low risk nature of the Marcellus reserves.

The Utica shale comprised 7.6 Tcfe of our 3P reserves. As I highlighted earlier, we've only booked approximately 12% of our acreage in the Utica as proved, so we have a lot of proved reserve growth ahead of us there. But we also have developments in 2015 that could increase the overall size of the resource highlighted by our 500-foot and 750-foot density pilots that we are conducting now and that we will monitor throughout this year.

Our year-end 2014 reserve report included the actual well costs that were achieved during the year and did not factor in any service cost improvements going forward. However, as along with the rest of the industry, we have been highly focused on well costs in order to protect our margins. We've met with every major service company that we use and have reviewed every line items for our AFE for potential savings. As of today's conference call, we've identify cost savings of approximately 10% our prior AFE. Our current identified reduction equates to a $1.0 million to $1.5 million savings per well, which is meaningful when you consider we have over 5,000 locations identified in our 3P reserves. The budget for 2015 had accounted for some of these savings, but not all, and we hope to realize further savings throughout the year.

Now on to our operational update. As Glen mentioned earlier, our net daily production for the fourth quarter of 2014 averaged a Company record of 1.265 Bcf equivalent per day, including over 30,000 400 barrels a day of liquids, or 14% of total volumes. Fourth quarter of 2014 production represents an annual organic production growth rate of 87%, and liquids production for the fourth quarter of 2014 represents an annual organic production growth rate of 172%.

As it relates to our drilling activity in the Marcellus, we are currently running seven rigs. We've transitioned the program to utilize SSL completions and all wells going forward, and virtually all of our 136 horizontal Marcellus wells drilled and completed in 2014 also utilize the SSL completion techniques. Of the 136 wells, 126 have been online for more than 30 days and had an average 30-day rate of 13.1 million cubic feet equivalent, and this is while rejecting ethane. So, that 13.1 million cubic feet equivalent was 15% liquids, again, rejecting ethane. The average lateral length for the 136 wells was approximately 8,050 feet.

In the fourth quarter of 2014, we placed online the four well Wagner pad, which had a combined peak 30-day sales rate of 59 million cubic feet equivalent a day, again, in ethane rejection, and had a heating content of 1,175 Btu. These are very strong 30-day rates, and our support of a continued transition of our development program into the more liquids-rich areas of our Marcellus leasehold position utilizing SSL completions.

Now I will shift to the Utica. We are currently running seven rigs in the Utica. Since the beginning of 2014, we completed and placed online 41 wells in the Utica. All of the 41 wells have been online for more than 30 days and had an average 30-day rate of about 16.2 million cubic feet equivalent per day, again, in ethane rejection. And so the 16.2 million cubic feet equivalent a day included 36% liquids. The average lateral length for these 41 wells was approximately 8,020 feet. The four well urban pad that was placed online during the fourth quarter and had an average heating content of 1,195 Btu had a combined 30-day sales rate of 74 million cubic feet equivalent a day on a combined basis, again, in ethane rejection, and so that equivalent rate included 16% liquids.

Antero continues to deliver the longest laterals among its Appalachian peers, we average over 8,000 feet in length in 2014. Regarding capital expenditures for the quarter, we invested $754 million on development, $57 million on certain gathering projects at the AR level, including freshwater distribution infrastructure, $101 million on base leasing and $222 million on leasing producing wells associated with a certain Utica acquisition. To further expand on this acquisition, the transaction consisted of approximately 12,000 net acres primarily located in Monroe County, Ohio, in the core of the Utica shale play. In addition to the undeveloped acreage, the acquisition also included producing properties with approximately 20 million cubic feet equivalent of current net production from five horizontal wells and an eight inches -- excuse me, eight-mile, 12-inch high-pressure gathering pipeline. This Utica transaction resulted in the addition of approximately 115 new drilling locations. In total, the acquisition represents over 1.0 Tcf equivalent of 3P reserves with an associated PV10 value of approximately $600 million, assuming year end 2014 SEC prices.

In summary, we had an outstanding 2014 development program that resulted in a peer leading growth in production and reserves, with some of the lowest development costs in the industry. Even though we've reduced the budget by 40% compared to last year, we remain the most active operator in Appalachia with the highest organic growth rates 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 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, even in a low commodity price environment. We have also preserved optionality to accelerate the development program, if warranted, by an improvement in commodity prices. With that, I will now turn the call over to the operator for questions.

(Operator Instructions)

Neal Dingmann, SunTrust.

A couple -- two questions. One: Just looking at that slide where you guys really lay out your -- I think you call it the realized price roadmap. Your thoughts on -- I guess beyond 2017. You certainly have a large amount that is obviously covered there. Two questions -- One: if you were to go and add some of this type of takeaway today, either -- obviously you have the expanding amount in the Chicago market, and especially in the Gulf Coast market.

I guess my first question is: What would that kind of FT cost you today? And my second question to go with that is: I forget -- how much do you have excess FT today that you are able to continue to market?

Neal, it is Paul here. Well, I would say it depends on which FT. We have lots of different segments. As you know, these segments add up to a little over 4 BCF a day, as they all come on, if you measure it in 2018; have a lot of pipes going to different areas. You know from our story that we were able to get in early on so many of these pipes.

And so, the early FT -- some of it was very inexpensive. It was exchange agreements, it was compression adds, it was reversals, and then now we are more onto new builds. As you know, more than half of our FT goes to the Gulf, through various conduits. So, that 4 BCF a day -- about 2 of it goes to the Gulf.

I guess I would just say that there are new expansions coming on, with higher prices on various pipes. REX would be one going west towards Chicago. Colombia would be another going south towards the Gulf. So, there's various ones.

Will we participate? Yes, in some; less so in others. The new Rover pipeline, we think, is a good project and pretty reasonable. I know that doesn't give you firm numbers, but it is definitely -- most of the new projects are much higher than where we are.

No, that's very good, thanks.

And then just one second one, if I could: Looking to slides that describe and really talk about that massive Utica dry gas position you have, in addition to your others -- I guess, now, and you mentioned in one of the slides now all of the operators that have seen some significant wells there, and I know you guys are drilling. Just your thoughts on how fluid your drilling plan is, based on the well results.

Obviously there's -- again, I'm looking at that slide that shows the returns between the highly rich gas and the rich gas versus the dry gas. And I'm just wondering if you all could comment -- how you think those three will differ going forward? Or based on the well results you've seen so far, you feel pretty comfortable with the economics of all three of those, and how different that plan could be.

Our focus is on the liquids-rich drilling, as we have emphasized in this call and elsewhere. That's liquids-rich in the Utica; liquids-rich in the Marcellus.

We have quite a good handle on the dry gas in the Marcellus. We've drilled a lot of wells there -- more than 150 wells over on the dry side. And they're very good EURs per lateral foot, but they are just not as strong compared to the ones that give us the liquids-rich premium. Feel quite knowledgeable about those.

Also feel good about the deep dry Utica we have in some of our slides that we not only have the down dip dry Utica in Ohio, which we have a good position, but underlying our Marcellus acreage, we have at least 160,000 acres of deep rights over in the northwest corner that look highly prospective for deep dry Utica. As you know, there has been a number of tests that are quite impressive along the Ohio River on both states, in West Virginia and Ohio. Probably the closest -- certainly the closest to our acreage is the Magnum Hunter well that had very impressive rates -- very strong bottom-hole pressure, big flow rates, and it didn't require that much drawdown of the reservoir to pull that much gas out.

Like our 160,000 acres of deep rights throughout that northwest Marcellus, but when would we shift gears to develop it? You have to consider, again, the gathering infrastructure; and the gathering infrastructure that we have built throughout that area, and that we plan on continuing to build, is all designed for rich gas. We collect the rich gas; we bring it to the plants and extract the liquids. And so, you wouldn't want to put the deep dry gas into that. So, it will require some infrastructure.

Right now, the takeaway on deep dry gas is not as favorable. But by the end of 2016 to mid-2017, the Rover project comes on, of which we have 800 million a day of firm. And so, that goes right through our deep Utica dry gas fairway.

I think probably between now and then, our focus is going to stay on the rich gas. Will we do some deeper dry gas once the Rover line comes on, so we can go directly into that line and into favorable markets? It's quite possible. I don't think we will be shifting over our entire program, but we may work some of that in. That's how we are thinking about it: focus on the liquids in both the Marcellus and the Utica, but like long-term potential of the deeper dry Utica play.

That's very helpful. Thank you.

Dan Guffey, Stifel.

Thanks for the comprehensive update. Just curious: Where are your 500- to 750-foot drilling pilots located? How many are expected in 2015, and what do you believe the optimum spacing will be across your various acreage windows?

We have done -- we are talking about the Utica, and so, everything we've -- when we talk about our resource, we talk about 1,000-foot interlateral distance. When we talk about our proved undeveloped, that is all on 1,000-foot interlateral distance. We have conducted pilots on 500 and 750s. The results, I would say, are encouraging, but too soon to tell. Naturally, the PDPs on 500s and 750s are booked on that interlateral distance, but everything else is on 1,000s.

And so, where within the Utica? It is within the rich, the highly rich, and the liquids trends. So, we're spread across the different BTU regimes. And so, we'll get a feel in all of them as to how that can work.

But I think that the very solid that we naturally feel are the lowest risk are just the 1,000-foot interlateral. And then we will just see through the course of this year how the others perform.

How about over in West Virginia?

In West Virginia, we have moved towards 660s on everything that we do. There's still some areas where we haven't demonstrated the 660s yet over on the far west side -- the southwest side of our acreage block. But it is less than 10% of our total that is still on 1,000s. So, everything else is on 660s, and certainly supported by the well performance.

Okay, great. The $150-million land budget -- how much of this is lease extension, and how much of this will be targeting new acreage?

It is almost all new acreage. The lease extensions are within the core of our block, and those values are very reasonable; so, much of it is new leasing.

Any acreage expirations in the coming year, too, outside on the fringe area -- outside of the core?

No, there's really not. We are in such a good position; I think more than 60% of our Marcellus is HBP'd, and so much of the rest is either 5-plus, or 5-plus-5s, 10-year. We have yet, in all of our drilling in either play, had to drill any wells to hold acreage, and don't foresee that happening.

Okay, great. And I guess one last one for me: You guys touched on how your well-completion designs have changed over the past year, but I'm wondering if you could discuss any expected changes or anything you are currently testing to further optimize well performance, in both the Marcellus and Utica?

Well, I think we have said it before, that I don't know if you ever reach perfection on frac techniques, so we are always judging and conducting pilots. But we have gone, of course -- we and the rest of industry -- towards shorter stage length. And the stage length that we model and that we believe feel good about is 200-foot stage length in the Marcellus, and 175 in the Utica.

We've gone tighter in the Marcellus, and we have a number of pilots on 150-foot interlateral distance. But it is too soon to tell as to whether you come out ahead. What you would expect is you will get higher recoveries, but it is higher costs; and so, time will tell.

Still have that working for a little shorter yet, but feel very good with the 200s. And that's what we go with as the standard formula or recipe across all of the Marcellus, with just these pilots, as I mentioned. Feel good about the 175-foot stage length in the Utica, and that is probably where we will stay for a while.

Okay. Thanks for all the detail, guys; appreciate it.

Jeoffrey Lambujon, Tudor, Pickering, Holt & Company.

Given the continued volatility in commodity prices here, seeing distress from -- increase across the industry, how do you think about the opportunity to consolidate acreage above and beyond the typical leasing program in either play?

Those opportunities are certainly out there. We've got an active land machine, and so we look at things all the time. There are bite-sized things that we are always doing that are probably not that significant to mention, but plenty of takeouts of smaller players -- just the smaller independents, where we will lease their deep rights or take them out entirely.

Plenty of distressed companies out there in the industry these days, and so our basins -- the Appalachian basin is no stranger to that, where some are distressed. But we really don't have anything on the planning horizon that we are going to jump at yet. We all know that we are only 12 weeks into the big commodity downcycle, so there is time, and we will be patient.

Okay. And then, on cost savings, are you able to quantify how much is baked into the budget at this point? And do you have any targets for savings incremental to the 10% that you mentioned earlier?

Well, I think we mentioned we feel good in that -- 6% range is what we've baked into the budget, and feel that 10% reduction is very reasonable. We have a lot of respect for our contractors. They've been with us for a long time, and so discussions have been under way. They understand the issues, and so there is definitely room for more, and have good response from our contractors. They want to continue with the working of their equipment.

The most straightforward thing to have a reduction on is labor. And so, that comes fairly readily. And then raw materials, whether it is gravel for a location, or sand for fracking -- those are the next to come in a little bit.

It is the ones where we have contracted with rig companies or frac companies -- we obviously respect our contracts, and so we are working with our contractors. Sometimes there is a restructuring of them, but that -- those folks are making payments to the bank, and so the reductions are a little harder in coming. We're respectful of that; but working with the contractors.

Can we manage the reduction up to, I don't know, maybe high side is 20%? It is possible. And it will be higher in some aspects, as I mentioned, like labor or materials, and lower in other parts.

Still a program under way, and I think many would realize, if you have a contract, the reduction on a rig is one thing. If you were to go out and pick up a new rig, the reduction would be quite a bit more -- that the day rates on uncontracted rigs are quite a bit lower. There will be a managing down of costs through time for the industry and for us.

Great. Thanks for the detail.

Ben Wyatt, Stephens.

Quick follow-up, maybe, I believe to Neal's question about the dry Utica. Just curious if you guys had any definitive plans on a Tyler test? And then, maybe as a follow-up to that: If the infrastructure was in place, just curious, from what you guys have seen so far, how this -- how the deep dry Utica would compare economic-wise to your other drilling prospects?

Yes, so, we had talked about a deep dry Utica in Tyler County, but as we've looked at it, and looked at the markets now, the takeaway is just not optimum yet to get to good markets. It is not easy to get to a good market, and we would most likely end up at Tetco M2 for deep dry Utica out of Tyler County, until the Rover pipe comes through, which, as I said, 1.5 to 2 years away. We have the Magnum Hunter Stewart Winland dry test -- I think that is the name of it. Yes, it is -- Stewart Winland -- only a few miles away, and down dip of us. We are up dip of that at where we drill our test.

It has already been answered a little bit as to what the section looks like, what the pressure is, what the deliverability is, and so, feel good about that. No plans for the near term to start trying to develop that again with that poor takeaway.

I think if you had reasonable gas prices, and we have the conduit to it, then that deep dry Utica can be competitive. Will it be as good as liquids-rich Marcellus or Utica? Questionable. I would say, if we had to weigh the probability right now, we would still think that the liquids-rich is probably going to be better, but time will tell. You really don't have much production history on any of the deep dry Utica yet

Okay. Very good. I appreciate that. That's all for me; thanks, guys.

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

This concludes our conference call today, and I would like to thank everyone for participating in today's call. If you have any further questions, please feel free to reach out to us. Thanks again.