Antero Resources Corporation (AR) Q4 2014 Earnings Report, Transcript and Summary

Good day and welcome to the Antero Resources Year End 2014 Earnings Conference Call and Webcast. All participants will be in 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 will spend a few minutes going through the financial and operational highlights and then we will open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com where we have provided a separate earnings call presentation that will be reviewed 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 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 am going to highlight the recently released 2015 capital budget and guidance, provide a review of fourth quarter price realizations and expectations going forward, including our substantial hedge portfolio and cover our 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 summarize operational goals 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 homepage 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 reviewing the correct slide deck during the call. Before we get in today’s topics, I just wanted to briefly revisit Antero Midstream IPO that happened in November 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 de-leveraging 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 6 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 to 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 taking us to 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 it internally is the testament to increasing productivity and capital efficiency in our development program. You might ask why reduced the budget at all with the attractive rates of return and substantial growth. While 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 returns at low commodity prices, the payouts on the wells lengthened from approximately 1 year or 2 years out to 2 years or 3 years thus 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. This will provide us with a substantial inventory of wells that can be completed in 2016 should prices improve. Slide #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 was a bit over 13 million a day equivalent per well in 2014, that’s the 30 day rate. If we decided to complete those wells in addition to our traditional activity, we could bring on almost 400 million a day equivalent gross well had production in the matter of months. And this is from the 50 wells that we have deferred into 2016. This inventory provides tremendous optionality and allows us accelerate our growth in 2016 if warranted by commodity prices. One last item to note on Slide 1 is related to the deferred completions is the timing of deferrals will be in 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 TETCO in the Marcellus is fully utilized until the fourth quarter of 2015 when we are scheduled gain access to a regional gathering pipeline which will result in NYMEX and TETCO based pricing going forward as we access additional markets. The strategy of wanting to bring our wells when this capacity is available results in higher well economics or about 18% improvement on IRRs despite the present value impact of the deferrals. To summarize our 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 #2 titled highest realizations in margins among large cap Appalachian peers. During the quarter we saw again another quarterly average production record for Antero 1.265 Bcfe per day net and sold 64% of our gas price at favorably priced indices that included TETCO, NYMEX and Chicago. So, remaining 36% of our gas was sold to Dominion South and TETCO which experienced significant price discounts to NYMEX throughout the year due to over supply 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 TETCO index and $6 million of gains at NYMEX Henry Hub. Including these hedge gains, our realized natural gas price was $4.39 per MCF or $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 are located in the Southern portion of the Marcellus where our local index is TETCO 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 the third party midstream revenues, results in a top line all-in price realization of $4.77 per Mcfe for the quarter. As you can also see on the Slide 2 this top line realization is $0.62 higher than our closest Marcellus peer. In addition to our all-in price realizations, I will also point out that we continue to the lead the way from an EBITDAX margin standpoint at $2.84 per Mcfe. When comparing this EBITDAX margin against our $0.61 per Mcfe 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 that our projects continue to generate high rates of return and high recycle ratios in the current gas and the oil price environment. Another important item to highlight in today’s commodity price environment is the hedge portfolio. It’s detailed on the Slide #3 titled largest gas hedge position in U.S. 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. Year end 2014, we had 1.8 Tcfe hedged with $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 commitments 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 the declining commodity price environment and that is significant PDP reserve growth and strong hedge growth. 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 of 2014, we have got total consolidated liquidity of 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 an attractive $0.24 per Mcfe, excluding non-cash stock compensation expense. EBITDAX for the fourth quarter was $330 million, 53% higher than the last year. And lastly for the quarter, we reported adjusted net income of $78 million or $0.30 per share or 6% increase over the prior year despite the approximate 10% decline in gas prices and 30% decline in oil prices. Before I turn 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 the financial perspective. We are well capitalized and continue to achieve tremendous growth with natural gas, industry leading price realization, 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 am going to review our 2014 development program highlighting our significant resource base and its low development cost nature. I will provide a brief update on service costs and discuss operational results for the quarter. We executed our 2014 development program ahead of the plan, as production and reserve adds 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 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 environment 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 had 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 have bottoms-up well by well development cost of $0.98 per Mcfe. These represent some of the lowest cost 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 our efforts in the Utica shale for 2015 on our rich gas areas, which provide the highest rates of return across our entire portfolio. Please look at Slide 5 entitled Utica development program target the rich gas regimes. The next 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 at 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 proved 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 have 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 will – 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 costs 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 have met with every major service company that we use and have reviewed every line item of our AFE for potential savings. As of today’s conference call, we have identified cost savings of approximately 10% from our prior AFE. Our current identified reduction equates to $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 Glenn mentioned earlier, our net daily production for the fourth quarter of 2014 averaged to company record 1.265 Bcf equivalent per day, including over 30,400 barrels a day of liquids or 14% of total volumes. Fourth quarter 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 have transitioned the program to utilize SSL completions in 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 on line 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. This is a very strong 30-day rate and are supportive of 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 on line 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 drill 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 8-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 peer leading growth in production and reserves with some of the lowest development costs in the industry. Even though, we have reduced the budget by 40% compared to last year, we have remained 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 have 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.

Thank you. [Operator Instructions] The first question comes from Neal Dingmann with SunTrust.

Good morning guys. Just a couple of 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 ‘17, I mean, you certainly have a large amount that’s 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?

Yes. Neal, it’s Paul here. Well, I would say it depends on which FTE there is 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 few measure it in 2018. So 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 FTE some of it was very inexpensive. It was exchange agreements, it was compression adds, it was reversals and then now we are more on to new builds. As you know more than half of our FTE goes to the Gulf through various conduit, so out of that 4 Bcf a day about 2 Bcf 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 is 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. So I know that doesn’t give you firm numbers, but it’s definitely most of the new projects are much higher than where we are.

That’s very good. Thanks. And then just one second one if I could, looking to the slides that describing really talk about that massive Utica dry gas position you have in addition to your others I guess now and you mentioned I think in one of the slides, now all the operators would have seen some significant wells there and I know you guys are drilling just your thoughts on sort of how fluid your drilling plan is based on the well results, I mean obviously there is again I am looking at that slide that shows the returns between kind of the highly rich gas and the rich gas versus the dry gas and I am just wondering if you all could comment how you think those three will differ kind of going forward or based on the well results you are seeing so far you feel pretty comfortable with the economics of all three of those and how different that plan could be?

Well our focus is on the liquids rich drilling as we have emphasized in this call and elsewhere. So 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 have drilled a lot of wells there, more than 150 wells over on the dry side and they are very good EURs per lateral foot, but they are just not as strong compared to the ones that give us the liquids rich premium. So 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 down 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 the 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. So like our 160,000 acres of deep rights throughout that Northwest Marcellus. But when would we shift gears to develop that, 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 this 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 ‘16 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. So, I think probably between now and then, our focus is going to stay on the rich gas where 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. So, 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.

The next question comes from the location of Dan Guffey with Stifel. Please go ahead.

Hi, guys. Thanks for the comprehensive update. Just curious where your 500 to 750 foot drilling pilot is located, I guess, how many are expected in 2015? And what do you believe the optimum spacing will be across your various acreage windows.

Well – so we have done we are talking about the Utica. And so, everything we have – when we talk about our resource, we talk about 1,000 foot interlateral distance. When we talk about our proved undeveloped, that’s all on 1000 foot interlateral distance. We have conducted pilots on 500 and 750s. The results I would say are encouraging, but too soon to tell. And so naturally the PDPs on 500s and 750s are booked on that interlateral distance, but everything else is on 1000s. And so where within the Utica, it’s within the rich, the highly rich and the liquids trends. So, we are spread across the different BTU regimes. And so we get a feel in all of them as to how that can work, but I think the very solid that we naturally feel are the lowest risk are just the 1000 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 is still some areas where we haven’t demonstrated the 660s yet over on the far west side kind of the Southwest side of our acreage block. But it’s less than 10% of our total that is still on 1000s. So, everything else is on 660s and certainly supported by the well performance.

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

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

So, any acreage expirations in the coming year or two kind of outside on the fringe area, outside of the core?

No, there is really not. We are in such a good position. I think more than 60% of our Marcellus is HBP and so much of the rest is either 5 plus or 5 plus 5, 10 year. So, 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 then I guess one last one from me, you guys touched on how your well completion designs have changed over the past year, but I am 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 have gone tighter in the Marcellus. So, we have a number of pilots on 150-foot interlateral distance, but it’s too soon to tell as to whether you come out ahead. What you would expect is you will get higher recoveries, but it’s higher cost and so time will tell. So, 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’s probably where we will stay for a while.

Okay, thanks for all the detail guys. Appreciate it.

The next question comes from Jeoffrey Lambujon with Tudor, Pickering, Holt & Company. Please go ahead.

Good morning. Thanks for taking my questions. Given the continued volatility in commodity prices here, seeing distress from increase across 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 have 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. So, plenty of distressed companies out there in the industry these days and so our basins, the Appalachian basin is no stranger to that, we are somewhat distressed, but we really don’t have anything on the planning horizon that we are going to jump back yet. I think we all know that we are only 12 weeks into the big commodity down cycle. 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 10% that you mentioned earlier?

Well, I think we mentioned we feel good in that 6% range is what we have baked into the budget and feel that 10% reduction is very reasonable. We have a lot of respect for our contractors. They have 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’s gravel for a location or sand for fracking, those are the next to come in a little bit. It’s the ones that 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. So, we are 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’s possible and it will be higher in some aspects as I mentioned like labor or materials and lower in other parts. So, still a program underway 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 pickup a new rig, the reduction would be quite a bit more that the day rates on contracted rigs are quite a bit lower. So, there will be a managing down of cost through time for the industry and for us.

Great, thanks for the detail.

The next question comes from Ben Wyatt with Stephens.

Hi, good morning guys. 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 the deep dry Utica would compare economic wise to your other drilling prospects?

So, we had talked about a deep dry Utica in Tyler County. But as we have looked at it and looked at the markets now, the takeaway is just not optimum yet to get to good markets. It’s not easy to get to a good market. And we 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 year and a half to two years away. We have the Magnum Hunter Stewart Winland dry test I think that’s 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 where we drill our test. So it’s already been answered a little bit as to what the section looks like, what the pressure is, what the deliverability is and so we feel good about that. So, no plans for the near-term to start trying to develop that again with that forward 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 still think that the liquids rich is probably going to be better, but time will tell. We really don’t have much production history on any of the deep dry Utica yet.

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.