Eclipse Resources' (ECR) CEO Benjamin Hulburt on Q4 2016 Results - Earnings Call Transcript

| About: Eclipse Resources (ECR)

Eclipse Resources (NYSE:ECR)

Q4 2016 Earnings Conference Call

March 1, 2017 09:00 AM ET

Executives

Douglas Chris - VP, IR

Benjamin Hulburt - Chairman, President & CEO

Oleg Tolmachev - COO

Matthew DeNezza - CFO

Analysts

Gabe Daoud - JP Morgan

Holly Stewart - Scotia Howard Weil

Kyle Rhodes - RBC Capital Markets

David Deckelbaum - KeyBanc Capital Markets

Brian Billy - Capital One Securities

David Beard - Coker & Palmer Investment Securities

Operator

Greetings and welcome to the Eclipse Resources Fourth Quarter and Full Year 2016 Earnings Conference Call. [Operator Instructions] And as a reminder, this conference is being recorded.

I would now like to turn the conference over to your host, Mr. Douglas Chris manager of investor relations, thank you, you may begin.

Douglas Chris

Good morning, and thank you for joining us for the Eclipse Resources’ fourth quarter and full year 2016 earnings conference call. I am Douglas Kris, and with me today are Benjamin Hulburt, Chairman, President and CEO; Oleg Tolmachev, Chief Operating Officer and Matthew DeNezza, Chief Financial Officer.

If you have not received a copy of last night’s press release regarding our fourth quarter and full year 2016 financial and operating results or reviewed our updated corporate presentation, you can find a copy of each on our website at www.eclipseresources.com. We will spend a few minutes going through the operational and financial highlights and then open it up for Q&A.

Before we start our comments, I would like to point out disclosures regarding cautionary statements in our press release and remind you that during this call, Eclipse management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Eclipse Resources and are subject to a number of risks and uncertainties, many of which are beyond Eclipse Resources’ control. Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Information concerning these factors can also be found in the company’s filings with the SEC. In addition, during this call, we do make reference to certain non-GAAP financial measures. Reconciliation to applicable GAAP measures can be found in our earnings release. We will file our 10-K shortly, which will be accessible through our website or the SEC’s EDGAR system.

I will now turn the call over to Benjamin Hulburt, our Chairman, President and CEO.

Benjamin Hulburt

Thank you, Doug. And thank you to everyone for listening to today’s call. Over the course of 2016 our industry experience many challenges. And I'd like to congratulate our team for remaining highly focused while achieving substantial operational success, that is positioned us to take advantage of our highly economic acreage foot print.

The last several months have been very active for Eclipses, as we have begun the process of accelerating our drilling and incompletions activity. Complemented by the innovations we have achieved through our super lateral program and our generation 3 completion designs. These innovations have been instrumental in allowing us to generate expected well level before tax internal rate of return, across our entire acreage position. In excess of 60% at year-end strip pricing. And in allowing us to increase our tight curves in both our Utica condensate and rich areas.

Throughout the downturn, we've sought to eliminate inefficiencies and our cost structure and has been successful at locking in the cost structure for the coming year in order to mitigate service cost inflation. Finally, we continue to see the fruits of a well-constructed transportation strategy. As shown by the commencement of our Utica access pipeline capacity into the TETCO pool. This capacity and the continue daily focus by our marketing team, allowed us to achieve strong natural gas differentials as we close out the year.

During the fourth quarter, our average daily production was above the high end of our guidance range for the ninth consecutive quarter at $255.3 million cubic feet equivalent per day. With the accompanying total revenues, increasing approximate 27% to $83.9 million. Our adjusted EBITDAX grew to $41.3 million for the quarter. All three of these metrics were above analysts' consensus expectations. Additionally, our per unit cash production costs during the quarter were $1.54 MCFE.

And excluding firm transportation expense we're just $1.13 per MCFE, also below the low end of our previously announced guidance and analysts' consensus estimate. For the full year 2017, our average daily production was 228.6 cubic feet equivalent per day, and our revenues were $235 million.

Our outstanding fourth quarter EBITDAX helped us to generate adjusted EDITDAX of $105 million for the year. I would remind everyone that these metrics include the five-month period in early 2016 when we were curtailing production in suspended our drilling operations.

On the expense side, our per unit cost production costs for the full year were $1.48 per MCFE, which was again better than our guidance and analysts' consensus estimates. Despite the low prices, utilize to determine our SEC conforming proved reserves, we were successful in growing our proved reserves by 35% compared to year-end 2015. The 469.4 BCFE. However, using forward strip pricing as of year-end 2016 our proved reserves volumes were approximately 1.2 TCFE representing of 108% increase relative to year-end 2015.

During the fourth quarter, the company drilled four wells. Completed 10 wells and turned seven wells turned to sales. Included in the turn to sales number is our holiday pad which was turned sales late the fourth quarter with a total of five gross wells. And includes our longest dry gas well to date, with a total measured depth of 24,578 feet. And a lateral extension of over 13,000 feet. This pad was the first dry gas pad completed using the generation 3 completion design. And we are extremely pleased with the performance of the wells to-date.

The wells continue to produce approximately 30% above our dry gas type curve, using our manage pressure drawdown methodology after approximately 80 days of production. These generation 3 completion combine slick water, tighter stage spacing, designer friction reducers, higher profit loading. In the - in the wells all incorporate our aggressive choke management an engineer flow back procedures.

Results across our phase windows incorporating these techniques. Are better than anything else we've seen and we continue to monitor these wells to assess the long-term impact to our tight curve expectations.

Eclipse is constantly striving to become more efficient and technologically advanced, in order to improve our well results. An increase EURs while lowering costs. We have demonstrated that would lead to play an arguably lead all plays in terms of lateral length, and have been consistently the lowest cost producer in the core of the Utica in terms of cost per foot of lateral.

For 2017, we are forecasting cost at approximately $818 per foot of lateral in our wet gas areas. And $935 per foot of lateral in our dry gas areas. Based upon our respective type curve assumption.

With our generation 3 completion technique, we've been able to observe higher fracture conductivity and stimulated reservoir volumes, ultimately leading to higher EURs, with combined with the demonstrated pressure management benefits of our region initiative of engineer flow back, designed to minimize profit province deterioration during the initial production periods of high water concentration. We are seeing further improvement in EURs and returns.

With the successful application of these techniques in our condensate and rich gas type group [ph] areas, we felt confident in increasing our tight curves in the Utica condensate and Utica rich gas areas we are - where we have significant data by proxy in the increase both type curves by approximately 16% and 22% respectively.

Finally, our early indications from the use of these techniques in our dry gas area shows results that are consistent with what we have already seen in the other areas in our extremely encouraging. As we move forward we will continue to assess the impact of these techniques on our dry gas area, and will adjust type curves if and when appropriate.

As we move into 2017. We're designing our drilling and completions program to take advantage of and build upon the success achieved in 2016. We are focused on extending lateral lengths of all the wells we drill during the year, an estimate we'll have an average lateral length in 2017 of approximately 13,300 feet.

We plan to drill 11 super laterals in this year's program, with lateral extensions in excess of 15,000 feet. Three of these super laterals are planned to be in the dry gas portion of our acreage. We believe that the company has validated the super lateral concept, not only by demonstrating that we can drill laterals and a cost structure that provide robust returns. But also, with consistent recoveries per foot as compared historical shorter lateral results.

With the super lateral program and our generation 3 completion design approach, we've redefined the return profile of our operations in the Utica Shale. As our type curve expectations demonstrate, we now estimate we can generate very attractive rates of return across the entire core acreage position, that are in line with and competitive with the best place in the country, even at today's low realized gas prices.

Our acreage is approximately 50% condensate oriented and 50% dry gas oriented, providing a very good mets [ph] of commodity exposure.

Eclipse will continue to focus on how we can innovate in 2017. For example, we were the first company to attempt a Utica Shale read our test, which we recently completed and had begun production testing on one of our vintage generation 1 dry gas wells. This requires only a modest amount of capital, and could be a basis for a broader program focused on a larger group of older wells.

We also will be drilling in our Marcellus area, the two well scheduled to start in the first half of 2017. We think this activity in the Marcellus is important, as the market has not yet described any real value to that acreage. That we believe will generate very attractive rates of return in cost comparison to our Utica corporate foot print area. For 2017 we have established a $300 million capital budget approximately 87% of this capital budget is dedicated to drilling and completions and assumes the addition of a second rig that we - that will begin drilling the rich gas and condensate portion of our acreage. We expect this flood approximate 21 net well during the year, and turn approximate 24 net wells to sales. As I previously stated, we expect these well that average lateral lengths of 13,300 feet. When comparing this to what we've seen from our other peers in and outside of the basin, drilling laterals from 6,000 to 8,000 feet, we're effectively putting the sales the same amount of lateral footage that we drilled 52 to 38 short lateral wells.

This plan is funded with cash on hand and cash flow from operations. And is expected to drive 35% growth in production year-over-year and an expected 25% three year compounded annual growth rate as we detailed in our recent analyst day.

Based on current prices and assuming a similar size $300 million annual capital program. Each year for the next three years, we believe that not only can we provide a robust 25% compound annual growth rate of production, but that we also have the balance sheet to fund that grow while be leveraging on a debt EBITDAX basis over the same period. We have the acreage, the team, the talent and the technical ability to further accelerate if market conditions warrant.

With that I'll turn the call over to Oleg, our chief operating officer.

Oleg Tolmachev

Thank you, Ben. Although it is strange to say it, [indiscernible] commodity price experience, 2016 was a very positive year for Eclipses. During the year, we put innovation the head of production growth, and then doing strategically enhanced our SVPs by increasing EURs while lowering cost for quarter productive lateral. As compared to 2015, We're drilling and completing wells for approximately 25% less per lateral foot.

We're also drilling well longer and use this significantly more aggressive completion designs. These advances culminated in the development of our super lateral program, and the creation implementation of our generation 3 completion design. Additionally, although these result of not yet fully reflected in our proved reserves at the year-end 2016. We're able to lower our F&D [ph] cost just $0.70 per MCFE in 2016.

During 2016. The combination of our generation 3 designed implementation of aggressive pressure management techniques, and the use of engineers flow back procedures, have allowed us to recently increased our Rich gas and Condensate. As mentioned in our guidance [ph], we continued to be excited about what we're seeing at our rig gas areas as well, based on implementation of the above mentioned techniques.

While we have seen only approximately two months of production in this area, was this approach initial results continue to be consistent with the results we’ve seen in other areas of the plate [ph]. For example, we're currently flowing wells 30% over our tight curve, and we receive pressure declines approximately 140 to 160 PCI per week. We will continue to monitor performance, as appropriate adjust curve to count for the changes we seen.

As we move into 2017. We will be continuing to focus on innovation while increasing activity and more broadly implementing designs that were successful during the last year. The average drill lateral length will be over 30,000 feet, and will include two compensate wells that are planned at over 19,000 feet. As part of this program. We will be testing various generation for completion design concept, including assessing the back of engineer tricks [ph]. The use of the diversion material and even higher proppant concentrations.

We have also very recently completed Utica’s first rig as already Ben, mentioned. In one of our old rig gas wells and have begun production testing on this exciting proppant test. During the first half of the year, we will also begin drilling two Marcellus wells. These wells will be approximately 8,000 and 10.000 feet in lateral length, and will be drilled in area of eastern Monrovia [ph] where we anticipate highly attractive results.

As we put these wells in line. We are excited for the potential to further grow up in the area that we have generally not focused on, and potentially add another rigs future drilling locations. I could not be more pleased with the activities and ideas of the team is considering, and expect 2017 to generate results that will equate the results experienced with 2016.

With that I will turn the call over to, Matt.

Matthew DeNezza

Thanks, Oleg. For the fourth quarter 2016 we continue to see solid revenue and cash flow generation. As our activity levels increased. Revenues for the fourth quarter was $83.9 million and are adjusted EBITDAX was a record $41.3 million. These metrics all exceeded our guidance range, as well as consensus estimate, and were driven by higher implant production realized natural gas prices and liquid prices, as well lower than planned components of our operation costs.

During the quarter, our all in realized price was $3.9 per MCFE, before the impact of cash settle derivatives, and $3.21 after this impact.

Our natural gas price differential before transportation expense was $0.16 negative per MCF. This pricing differential exceeded our guidance range, and benefited from the fact that we now commence sales into our 205 million a day of capacity on Columbia gasses Utica access project. This is the bespoke project that Eclipse and Columbia put together with dominion, and allows us to move our gas through the dominion system into the TCO pool.

Turning to our oil sales. Our realized oil price during the fourth quarter of $44.51 per barrel implies a negative $4.63 differential WTI. This differential is substantially better than the tight end of expectations, and was driven by continued improvement in the supply demand situation in the basin.

Additionally, we're working to further enhance our economic, as we begin to market condensate volumes and sell directly to local buyers beginning in April. We're excited to announce that we have finalized an agreement for the purchase of our condensate barrels, beginning in April of this year and remaining in place through the end of 2018. As part of this process, we're locking in the differentials that are inclusive of cost of trucking, yet still relatively consistent with differentials realized in 2016 before deducting trucking costs. The expected results will be a reduction in condensate related operating costs while still achieving strong differentials through 2018.

Given this dynamic. We have tightened our full-year condensate differential guidance range by $1 per barrel and see improvement in operating expectations as the new arrangement progresses.

As we look at our NGL sales during the fourth quarter, we realized a $21.22 per barrel NGLl price, equating the 43% of WTI. This price realization was positively impacted by an [indiscernible] pricing cross our NGL price barrel.

During the quarter, NGL prices were positively impacted by the moving proved prices, and by increasing movement of ethane and other products to export markets.

Moving to our cash production costs, we achieved per unit cost of $1.54 per MCFE. This includes $0.41 per MCFE, and transportation expenses and was below expectations due to across-the-board improvement per unit expense line items including direct LOE and saltwater disposal expense.

For the fourth quarter, our $57.8 million of capital expenditures consisted of $49.6 million in drilling completion capital $1.7 million of midstream expenditures and $6 million in land related capital. For the full, year we spent approximately $177 million.

The key driver of this reduction reported spend, was relative to our capital budget, was driven by reducing well cost and timing adjustments associated with our drilling completion plan. From a liquidity perspective, we ended 2016 with $342 million a pro forma liquidity. This consists of $201 cash and $141 million of availability on a revolving credit facility, after getting effect to the $34 million of outstanding laterals in credit.

This liquidity also assumes the increase in borrowing base, related to our recent bank extension process that we close this past week. As we previously announces our borrowing base increased by $50 million to $175 million and we extended the maturity the facility up to 2020. This liquidity puts us with a strong position to find our expected capital requirements, and allows the company to continue to grow cash flows, and enhance credit metrics.

As we consider our previously announced capital budget, we anticipate funding this spend with cash on the balance sheet and cash flow from operations. Current forecast suggests minimal if any revolver utilization, will require - will be required to support this 2017 budget.

Given the increase in activity associated with our three-year program, I expect to see this facility continues to grow as we progress through this three-year plan.

From a hedging perspective. Eclipses continue to focus on enhancing margins and protecting cash flows and taking additional steps to manage natural gas price risk, associate with our 2017 and 2018 natural gas production.

Overall in 2017. We now the vast majority are protected natural gas production hedged an average for price of $2.87. And for 2018 we currently have over half of our projected natural gas production hedge. We have generally use colors, in three way colors for these hedges, in order to maintain upside is the supply demand balance improves over the coming season. This is demonstrated by the fact that the upper band of our portfolio, reflects an average ceiling price of $3.35 per MMBTU for 2017 at $3.37 per MMBTU in 2018. We're certain of our hedges are lining for upside participation to as high as $3.57 in 2017 and $3.75 in 2018.

To conclude my remarks, I would say that our performance for the period was quite positive. We beat production expectations, exceeded EBITDAX guidance and consensus levels and continue to be well positioned with ample liquidity and a strong balance sheet. On that note, Ben will wrap up our prepared remarks.

Benjamin Hulburt

Thank you, Matt. I believe that we continue to distinguish ourselves through our operational execution; a relentless pursuit of innovation and through our ability to efficiently developed and maximize the returns from our asset base. I'm extremely pleased with our team, who has once again delivered a strong operational performance, and positioned us to provide one of the most exciting growth profiles among our peers.

Our 16 years of drilling inventory, the continued market acceptance of our super laterals, the completion of our analysis of our dry gas generation 3 wells, the implementation of our generation 4 completion methods, the evaluation of our Utica Shale refract pilot test program and the upcoming drilling activity in our Marcellus acreage, continue to illustrate the strong potential for continued growth over the coming quarters and years.

Operator at this time, please open the phone lines for questions.

Question-and-Answer Session

Operator

[Operator Instructions] First question comes from the line of Gabe Daoud with JPMorgan, please state your question.

Gabe Daoud

Good morning, Ben. Good morning everyone. Maybe just starting with the Holliday Pad and dry gas area, some good performance so far from generation 3, just trying to get a sense of how much production day-to-day you think you guys would need before potentially bumping that curve higher, and I think in the condensate area, I think with Gen2 - excuse me Gen3 probably about six months or so - update that you had and then the rich gas area with Gen2 was falling probably about 24 months or so. Just trying to get a sense of the timing of yours.

Benjamin Hulburt

Sure, Gabe. You're right on that duck well the generation 3 wells in the condensate area as well as the purple haze, we had anywhere from six months to upwards of the year on the purple haze well, even though that was technically a generation 2 design. I think our expectations at this point are with six to eight months of data. And we can more accurately estimate a new type curve if ultimately that is the decision. So worked up probably looking at another two to three months, we want to be very careful that we do not increase a tight curve and determine later that we were too aggressive.

Gabe Daoud

Thank you, Ben, that’s helpful. Follow up I guess just moving to your outlook that you guys provided at the analyst day, can maybe just talk about the flexibility you have in either accelerating or decelerating activity relative to the current year outlook, I know you locked in some pricing over the next couple of years, just trying to think about the flexibility you guys want to have.

Benjamin Hulburt

Sure, well, for the more pessimistic view on the decelerating side, we have made sure to maintain flexibility both on our drilling rigs as well as our completion contracts. And we have very, very little if any contractual commitments that would prevent us from having - from being able to slow down if we chose to do that. However, giving our extensive hedging program, we don't really see that in the cards, but we do have that contractual flexibility if we need it.

On the upside, we went public in 2014 and we were running four rigs, and certainly still have the operational capability to do that, as well the drilling inventory. Obviously, that requires more capital. And I think today's commodity prices probably not in the cards at least in the next 12 months. But if we saw commodity price increases, we would very likely further increase that activity closer up to what we are doing at our IPO timeframe.

Gabe Daoud

Good, that’s helpful. And then just I will sneak one more in, I know it’s not kind of exposure, but you obviously have $50 million a day on [indiscernible], just curious maybe you can share with us some of your thoughts on trance Canada's [ph] second attempt now - production is successful I guess, how you think that could impact the market moving forward, particularly on done, obviously.

Matthew DeNezza

Yes, this is Matt. Certainly, we're watching that, I would describe it as you guys are from the outside looking in and don't have really proprietary or any special knowledge of how that process evolves. I do think maybe more importantly than that is just how over time that market reacts to Rover and most likely nexus [ph] moving into that base, and that that feels like more of a - kind of a near term pressure on that market, I think if you look at dawn basis sat and say something like 2019 where it's likely both these pipes are in and flowing, that probably widened out that basis by about $0.20 around some of the recent Nexus [ph] and Rover announcements inside, I kind of feel like those moving into those - those pipes moving into that market is probably what's causing more that movement in bassist and then trance Canada's activities.

Gabe Daoud

Thanks, Matt, that’s helpful. Thanks guys, I will jump back in.

Benjamin Hulburt

Thank you.

Operator

Thank you, our next question comes from the line of Holly Stewart with Scotia Howard Weil. Please state your question.

Holly Stewart

Good morning, gentlemen.

Benjamin Hulburt

Good morning, Holly.

Holly Stewart

Just Ben, I think - I think we missed your comments on when the second rig was going to be added.

Benjamin Hulburt

Second rig is being added it in the first half of the year.

Holly Stewart

Okay, in the first half of the year. And then that 25% three years trigger, is there rig count associated with that number we should think about.

Benjamin Hulburt

We really haven't - haven't given any guidance or really think of it in terms of rig count, it is really more how many - net 13,000 foot wells a year, we would drill and put to sales and essentially it is the same size program as what we're running in 2017.

Holly Stewart

Okay. Okay perfect, and then Matt, maybe on the NGL realization, bumped the 1Q guide but kept a full year constant, just curious if it's just early and you want to be conservative verse there anything out there that's making you a little cautious on the realization through the year.

Matthew DeNezza

I mean, I think it it's really driven more by the sale cycle on NGLs, which is basically a lot of the NGLs what occurs is well float on mount Belleview during the course of the year, with a fixed deferential, and that sale cycle is basically in April to April process, so that it's occurring as we speak. And so really as we think about Q2 through Q4 and really through Q1 of 2018 will have a little more knowledge there, once that sales process that Blue racer [ph] and dominion tend to manage, it is complete. And so we just didn't have a lot of ability to change that given - or at least a reason why to change it now and have to move around based on better information here in a month or two.

Holly Stewart

Okay. And then it may be also with the 1Q production guidance adjustment, any I guess thoughts or color to share on how we think about the progression of the remaining three quarters.

Benjamin Hulburt

Sure, Holly. We didn't adjust the annual guidance yet just because it's so early in the year. But it's really just an effort to be conservative.

Holly Stewart

Okay. Alright, great guys. Thank you.

Benjamin Hulburt

Thank you.

Operator

Thank you. Your next question comes from the line of Kyle Rhodes with RBC capital markets. Please take your question.

Kyle Rhodes

Hey, good morning guys. Just one for me. [Indiscernible] dropped pretty sharply the fourth quarter, how should that be trending in 2017 as more Condi [ph] well is completed and just wanting to maybe split out the component of your production costs guidance for 2017. I guess I'm most interested in the assumptions for LOE and the firm transport piece of the GP&T lines [ph], thanks.

Benjamin Hulburt

We have a traditionally broken down that guidance on a line item by line item basis. As we look at - what I guided is to think about mix is probably a better way to think through it, and for the most part I think that our views are mix from a percent gas perspective, in the first half is relatively constant about 75%, maybe moves up a couple percent more in the second half as we bring on some bigger gas pads right toward the end of the second quarter. So that at the end of the day causes you to have an overall OpEx profile that declines over the course of the year, as you gas component moves. Additionally, we'll see in April as we get this condensate contract in place, we will see some incremental OpEx drop out as well as the fixed differential were paying effectively includes the cost of trucking, which historically is been an OpEx component. So we will have a better sense of that once we get into the contract, and can see the real impact of it, but yeah that'll help move OpEx of quarter-over-quarter basis down as well.

Kyle Rhodes

Appreciate the color guys.

Operator

Thank you, your next question comes from the line of David Deckelbaum with KeyBanc Capital Markets. Proceed with your questions.

David Deckelbaum

Good morning, Matt, Ben, and Tom Oleg, thanks for taking my question.

Benjamin Hulburt

Morning.

David Deckelbaum

Ben, I wanted to go back something you're talking about with the multi-year plan, which was really I think you said not really a function rigs but the number of high ends of 13,00 for laterals. Given that you guys are pushing that, I just want to confirm that the multi-year guide is based on sort of a perpetual 13,000 foot lateral average, and I guess is it reasonable to assume that those numbers could be adjusted higher in next few years.

Benjamin Hulburt

Well, yes. To answer both of your questions, the answers is yes. 13,000 is kind of a minimum that I would see them being an average, of course always have the occasional short lateral just because a unit can’t fit it, but on average I would expect the minimalist 13,000 feet. With a decent likelihood that that average continues to actually, grow above that.

David Deckelbaum

I just have a question about the Gen3, the Gen4 I guess the sample size of Gen 3 wells is large enough to move up the pipe curve, we've seen costs increased somewhat just incorporating the larger jobs here, and seemed like you guys have insulated yourself from a bit more service cost inflation. I guess internally how are you guys thinking about targeting may be a well cost reduction given the recent 3 [ph] completion designs. You know how much a prior maybe Oleg to opine on, just what portion of that completion design might be a little bit excessive at this point whether it's on the fluid side or where do you think you can get these costs down to a more efficient level.

Oleg Tolmachev

Well, I think the major components of completion costs is the cost of [indiscernible] we pump more designs, that potentially could result in a slight increase in costs, the water cost associated with that, but you know the way we look at it, we assess our switch to completion designs the functional wells. And then the SMG [ph] cost well, is purely driven by the economics metrics. As we think about spending more money on our completions.

Benjamin Hulburt

I think one thing to point out David, and I'm sure you've been noticed this that even despite the generation 3 completion design, which involves a lot more profit, we've been able to actually decrease our cost per foot of lateral year-over-year. When factoring in service cost inflation. Part of that because we've locked in so many of those costs, and part of it is because of the longer lateral. So despite pumping more than twice the amount proppant than we historically did, our cost per foot of lateral is actually decreasing.

David Deckelbaum

I appreciate that. And one more if I might, just given - you guys are certainly averaging the longest amount of average lateral feet. I think of any public company that I'm aware of. And you guys kind of push that single and technological side, are you seeing opportunities for either partnership development agreements or things like that where you could kind of enhance your inventory or value, maybe with some neighboring operators that perhaps don't have the technology or desire to go after some of the above acreage to your maybe condensate area.

Benjamin Hulburt

To answer your question simplistically, yes. It is our number one objective this year to grow the asset base. Whether through grassroots leasing [ph] or acquisitions and probably a combination of both. We are actively engaged in looking at ways that we can further employ this leading edge operational capability that I believe we've developed. So very, very active on the M&A front looking at every idea that we can come up with.

David Deckelbaum

Appreciate that, Ben. Thanks guys.

Benjamin Hulburt

Thank you.

Operator

Thank you, your next question comes from the line of Matthew Sorenson with Seaport global securities. Please state your question.

Matthew Sorenson

Hi good morning, thanks for taking my question.

Benjamin Hulburt

Good morning.

Matthew Sorenson

Following up on Holly's question. I was hoping you guys could expand a little bit on where you think NGL realizations could go in 2018 after the startup of refer to later this year?

Benjamin Hulburt

When we look at `, I'd certainly expect on an annual average basis to see if it improved based on Forbes right now. Our pricing is tight, indexes. We see that improving. I think as you compare it on a seasonal basis, the value and the pipeline is more so on the summer months right when regional demand locally is lower and so the price spread expands and there's less seasonality to Asian supply demand issues or Asian pricing. I think it's going to be a seasonal kind of fluctuation that you'll see in propane and butanes in terms of the value uplift. Right now we're not taking a number to it just because we have seen far east Asia pricing relative to Mont Belviu pricing be relatively volatile. But right now when we look at it, it is an uplift. I just don't want to guide on what that likely looks at as the pipe comes on.

Matthew Sorenson

Okay. Thanks. That's very helpful. Turning to your refract, can you talk a little bit about what you guys are looking for there? How you would define success on that front and what the opportunities could ultimately look like?

Benjamin Hulburt

Sure. Basically what we're trying to test is can we access new rock. Can we access rock that wasn't effectively stimulated with original completions designs? This test is first in the dry gas and I would caution as very, very initial. Our initial assessment is we're very pleased with what we're seeing in terms of the rise in pressures that we've seen, but we've just started flowing the well back in the last 48 hours. But the way the process treated and what we're seeing with initial pressures is very encouraging. The next step would be to probably test it more in a condensate area - an area where you've got a different liquid yield and pressure `. There's a long way to go until you roll this out over a very large block, but the initial testing looks pretty positive and it's not a terribly capital-intensive process.

Matthew Sorenson

Okay. Any color there on the capital side? Kind of what the typical cost of the single refract would look like?

Benjamin Hulburt

It's generally about a million dollars a well.

Matthew Sorenson

Okay. Thanks very much.

Benjamin Hulburt

Thank you.

Operator

Thank you. Our next question comes from the line of [indiscernible] with Guggenheim. Please state your question.

Unidentified Analyst

Hey, guys. Good morning. It's Marshall.

Benjamin Hulburt

Good morning.

Unidentified Analyst

Just a quick question on your leasing efforts, I know you guys have been pretty active up there particularly in the `. If you could kind of give us an update on competitive environment you're seeing up there as a lot of guys focus on the dry gas, what the environment is you're seeing there on leasing and leases rolling off as well as maybe larger scale AND in the basin.

Benjamin Hulburt

Sure. And one thing I would correct there is we are just as aggressively leasing in our dry gas area and actually have added more acreage there than we have in condensate. So we are actively leasing in both areas. It's competitive no matter where you go in the core of this play or probably any play. It's certainly competitive. I would say the leasing is at the point where each of us - ourselves and our competitors are leasing this still in specific units. So often it's rather obvious where a certain partial should reside in someone's chilling program. But it is very competitive. Certainly dry gas leasing is more expensive at least currently and there aren't as many companies focused on the condensate area like we are, nor do I think there are as many companies that really has demonstrated the ability to make that part of the play work the way we have. But it's still competitive even in the condensate area.

Unidentified Analyst

Got it. Thanks. And then just one follow up on one earlier on the Gen-3 to Gen-4 transition. Can you give us some more color on sort of things you'll be testing here in Gen-4? Is it just higher in tighter spacing, or is there some other sort of special sauce with advanced diverter technology or other things like that?

Matthew DeNezza

We're going to be - as we mentioned, we are going to think higher problem concentrations which will require some additional tweaking to our of design. We are going to be testing the extent to which engineered are applicable in these wells. We are actually as we speak. We are also going to be planning and we are currently using advanced diversion technology which both was utilized and refract well, but also in two or three of our currently completed wells to address connectivity between pass, but also to improve the overall simulated rough volume in each one individually. And really when you look at what drove the increase in EURs and production rates from Gen-1 to Gen-3 broadly speaking is the increase in SRE, which came from the Gen-3 design `. So we're hoping to continue to capitalize and drive up, to stimulate a rough volume for each well at our Gen-4 well as well.

Unidentified Analyst

Very helpful. Thanks, guys.

Operator

Thank you. Our next question comes from the line of Brian Billy with Capital One Securities. Please state your question.

Brian Billy

Good morning, everyone. Thanks for taking my questions.

Benjamin Hulburt

Good morning, Brian.

Brian Billy

Quick question. You mentioned the 16 years of German inventory across your asset base. Can you mention maybe what lateral length that assumes? Is it a similar 13,000-foot lateral length for future wells kind of going flat forward? And then also on the CapEx spend, is it similar to current levels of about $300 million for the spending side?

Benjamin Hulburt

Yes to all of your questions. inventories based on a 13,000-foot lateral program with acreage risking applied to it and it assumes the 2017 pace of drilling which is roughly 22 to 24 wells a year with 13,000-foot laterals and that is essentially exactly what's assumed in 2017, 2018 and 2019 and the three-year plan. So $300 million a year, 22 to 24 wells averaging 13,000-foot laterals each year over that three-year period.

Brian Billy

And then beyond 2019 as well?

Benjamin Hulburt

Yes. We haven't given guidance out farther than that three-year period. If you want my opinion, we'll look like in a very, very different company at that point and probably have expanded the asset base considerably by then as well.

Brian Billy

Got it. That 15 years of course will be evolving, but it's kind of on flat expectations?

Benjamin Hulburt

Yes.

Brian Billy

Okay. Thank you very much for the color.

Benjamin Hulburt

Thank you.

Operator

Thank you. [Operator Instructions] Our next question comes from the line of David Beard with Coker and Palmer Investment Securities. Please state your question.

David Beard

Hi. Good morning, gentlemen.

Benjamin Hulburt

Good morning.

David Beard

Most of my questions have been asked, so I see a little bit of a bigger picture hedging versus your three-year outlook, given that you're putting in some hedges around 290. Would you be comfortable sort of hedging at that price, keeping the two-week program for the next three years? You obviously would like to see higher prices, but is that status quo price level relative to hedging?

Benjamin Hulburt

Yes. Generally we're focused on the forward 24 months. 2017, we're pretty well meshed out. We have actually begun to taking advantage of some of the recent price downturn to utilize that to actually increase some of our ceilings. Because in all of the weather, it's certainly been warmer than we'd all like to see in the winter. We still believe the market is fundamentally under-supplied on gas and that the future demand increases that are going to begin happening in the second half of '17 has not been fully recognized or understood by the market. So we're actually taking advantage of some of these to look at increasing ceilings. In '18 where we're anywhere from 50% to 60% hedged, we still have another 20% that we will continue to layer on additional hedges. Actually in the first quarter of 2019, we've begun to layer in hedging program. So we just constantly evolving process. I would also say it's pretty rare that we just layer on the hedge and forget it. That's programs are confidently and looking at an outstanding position and trying to figure out how we can improve ROI. So we are constantly working on that as well. But generally, the objective is to be hedged, 24 months out.

David Beard

You guys are helpful. Thank you.

Benjamin Hulburt

Thank you.

Operator

Thank you. There are no further questions at this time. That does conclude our question-and-answer session. At this time, I'll turn it back to Ben Hulburt for closing comments.

Benjamin Hulburt

Thank you. I'd just like to thank you all for participating in today's call and look forward to seeing you all soon.

Operator

This concludes the conference call. Thank you for participation. You may disconnect your lines at this time.

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