Eclipse Resources' (ECR) CEO Benjamin Hulburt on Q4 2017 Results - Earnings Call Transcript
Eclipse Resources (NYSE:ECR-OLD) Q4 2017 Earnings Conference Call March 1, 2018 10:00 AM ET
Executives
Douglas Kris - VP of IR
Benjamin Hulburt - Chairman, President and Chief Executive Officer
Oleg Tolmachev - Executive Vice President and Chief Operating Officer
Matthew DeNezza - Executive Vice President and Chief Financial Officer
Analysts
Holly Stewart - Scotia Howard Weil
Mike Kelly - Seaport Global Securities, LLC
David Deckelbaum - KeyBanc Capital Markets
Ronald Mills - Johnson Rice & Company
Stark Remeny - RBC Capital Markets
Owen Douglas - Robert W. Baird & Co.
Operator
Greetings and welcome to the Eclipse Resources’ Fourth Quarter and Full-Year 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded.
It is now my pleasure to introduce your host, Douglas Kris from Eclipse Resources. Thank you, sir. You may begin.
Douglas Kris
Good morning, and thank you for joining us for Eclipse Resources’ fourth quarter and full-year 2017 earnings conference call. With me today are Benjamin Hulburt, Chairman, President and CEO; Oleg Tolmachev, Chief Operating Officer; and Matthew Denezza, our Chief Financial Officer.
If you have not received the copy of last night’s press release regarding our fourth quarter and full-year 2017 financial and operating results, you can find a copy of it on our website at www.eclipseresources.com. We will spend a few moments going through our operational and financial highlights and then open the call up for Q&A.
Before we start our comments, I would like to point out our 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 risk 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-Q later – 10-K later today, which will be accessible through the SEC’s EDGAR system. Also, we have posted an updated Investor Presentation incorporating the results from our quarter and full-year to our website.
We will now turn our call over to Benjamin Hulburt, our Chairman, President and CEO.
Benjamin Hulburt
Thank you, Doug, and thank you to, everyone, for listening to our call today. During 2017, Eclipse Resources had substantial operational and strategic success, leading to an expansion in our asset base, a substantial increase in cash flow, and the addition of a strategic joint venture partner. Through these actions, we increased our undeveloped acreage inventory by 57%, generated 85% year-over-year growth in EBITDAX and established a strategic drilling joint venture bringing in over $290 million in drilling capital.
During the fourth quarter of 2017, our average daily production was 311.7 million cubic feet equivalent per day, which was a 22% increase over the same period in 2016. Our revenue was $104 million, a 24% increase over 2016. Additionally, our adjusted EBITDAX grew to $53.5 million for the quarter.
I’m pleased to report that both of these financial metrics were above analysts consensus expectations. For the full-year 2017, our average daily production was 310.7 million cubic feet equivalent per day, a 36% increase over the previous year. Our revenues grew to $383.7 million, a 63% increase over the previous year and our EBITDAX grew to $189.1 million, an 85% increase over the previous year.
On the expense side, our per unit cash production costs, including firm transportation costs fell to $1.35 Mcfe, a 10% reduction from the previous year and our cash G&A costs fell to $0.31 per Mcfe, a 21% reduction from the previous year.
At year-end, we reported year-over-year reserve growth of 211% to 1.46 Tcfe based on SEC pricing. This included 344% growth in the liquids component of our proved reserves. For the year ending 2017, our drilling, finding and development costs continued to improve to just $0.26 per Mcfe and our all sources F&D improved to just $0.31 per Mcfe.
Operationally, the company had an outstanding [Technical Difficulty] in 2017, the company drilled 29 gross wells with an average lateral length of approximately 13,500 feet. This number includes 12 super-laterals drilled, including eight wells with lateral length in excess of 19,000 feet, and an average spud to TD drilling time of only 16 days. The drilling efficiencies we have been able to achieve are translating into per foot drilling cost that are 5% to 10% below our estimates.
Our two Marcellus condensate wells are drilled and completed during 2017, with an average lateral length of approximately 9,000 feet. We turned these two wells to sales late in January and so far we are pleased with what we’re seeing to date. The Marcellus in this area of Southeast Ohio is condensate-rich, and we remain excited for the prospect of becoming a more meaningful part of our drilling program in the future, as we can now co-develop, both the Utica and the Marcellus off of the same pad.
The company has put forth a significant effort in the stacked pay area to assemble acreage where we can drill laterals from 15,000 to 20,000 feet in each formation further lowering our cost structure. In addition, with approximately 78 additional Marcellus locations, based on our current assumptions, we continue to see this as a value driver for the market that the market has not yet focused on.
As we have discussed at our recent Analyst Day event, the company made the strategic decision last year to reorder the drill schedule and focus on the condensate portion of our acreage. This decision has allowed us to take advantage of the improvement in the near-term oil macro outlook, while additionally allowing us to achieve more commodity product diversification.
For the full-year 2018, we plan to turn 13 gross, nine net Utica condensate wells to sales, with an average lateral length of approximately 16,300 feet. At the midpoint of our guidance range, this will grow overall production on a year-over-year basis by over a 11% and will grow our condensate volumes by over 42%.
Liquids exposure is something we want to continue to increase and is one of the aspects of our company that makes us unique in Appalachia. Given that approximately 40% of our acreage is in the liquids area and produces a significant amount of condensate, we remain highly advantaged versus our Appalachian peers with single well rates of return that are highly competitive with some of the best plays in the country.
Looking to 2018, we expect to continue to advance our industry-leading drilling advantage by drilling an average lateral length on our wells of approximately 16,800 feet companywide, a 24% increase as compared to 2017 and over 80% longer than the average tight curve lateral length of our Utica peers.
Additionally, we have recently announced the renegotiation of our dry gas gathering agreement that will provide for a 20% reduction in our Utica dry gas gathering rate, providing for an incremental improvement on our per unit operating expenses.
Within the next couple of weeks, we will spud our first Flat Castle project area well in Pennsylvania. Our enthusiasm for the project area has continued to increase based on the recent industry wells in the immediate area of our acreage, as well as our analysis of full core we have acquired in the project area very recently.
We’re active in the engineering and development of the permitting and water infrastructure requirements that will support a 2019 development program on this asset. We continue to be excited by the potential we see in this area and look forward to bringing our initial well online early in the third quarter.
We’re committed to appropriately managing our growth levels in liquidity with a focus on managing cash flows as opposed to production growth, ultimately allowing us to achieve meaningful full cycle corporate returns. With a continued application of our many innovations and the well performance we have been able to achieve, we remain highly confident in our expectations for the full-year 2018.
With that, I’ll turn the call over to Oleg.
Oleg Tolmachev
Thank you, Ben. Eclipse continues to lead the industry in a wide spectrum of advanced drilling completions and reservoir technologies, such as new-generation of steering tools that are designed to drill laterals over 20,000 feet in length, drilling new equipment and processes engineered specifically for super laterals, engineered completions, new build and plug technologies that lead to significant cycle time reductions and IRRfocused predictive reservoir modeling.
Deep integration of the geological, petrophysical and reservoir models with a large production dataset allows us to create field development, drilling and completion designs unique to each producing unit and individual well with the sole goal of enhancing full cycle economic returns.
Parameter such as well spacing, proppant loading, stage length, well length are evaluated and tweaked again on an individual well basis to honor the reservoir model and service and commodities pricing and to produce the optimized rate of return.
We’re now at a point where our robust predictive models drive significant variability and drilling and completions designs creating very real value. All of our engineering and operations initiatives are focused on creating the maximum economic returns in our drilling portfolio.
From a drilling perspective, we recently TD the Yellow Rose A 2H well with a completable lateral length of over 19,200 feet located in our Utica dry gas area. This well is our and likely any ones longest dry gas well to date. The total measured depth of this well is 29,744 feet and we drilled this well in only 25 days spud to TD with the lateral sections drilling approximately 10.2 days.
The super lateral technology coupled with our proprietary predictive reservoir model, which molds completions designs with a focus on well IRRs has pivoted us – has provided us with a competitive advantage, as we look to expand our footprint to the new Flat Castle project area.
The Flat Castle area is a perfect ground for the application of our unique super lateral technologies and proven operational abilities. We continue to believe that this type of well design and operational performances is poised to disrupt the conventional notion of the play economics, as it preserve the high fixed costs associated with spud development and the vertical portion of the well over longer completed lateral, while deploying completions capital in the most effective way specific to each particular well.
To date, we have drilled 14 super laterals with an average lateral length of approximately 18,300 feet. For 2018, 73% of the wells with spud will exceed 15,000 feet in lateral length, and we plan to deliver on our goal of 24 super laterals.
In a dry gas portion of the play, Eclipses generation of three dry gas wells have outperformed our tight curve from the cumulative production standpoint. We have analyzed a very extensive dataset to establish whether or not we see any deterioration of EURs caused by an accelerated production profile in dry gas. Through this analysis, we have established that as long as the engineered flowback methodologies flows, we do not see any negative changes to the EUR relative to higher production rates of up to 40%.
We have now adopted this production approach and anticipate an approximate increase in IRRs of 12% in the dry gas area, while additionally allowing us to accelerate cash flows. This becomes especially impactful in times when the near to mid-term commodity price curves is – price curve is backward dated.
In addition, we have begun a similar evaluation in our Utica condensate area. This analysis is a lot more involved in a three-phase reservoir, where we’re dealing with a different reservoir flow regimes so the function of more complex PVT system.
I expect that in two, three months, we’ll determine whether to raise the production profile in our condensate acreage is accretive to the economic returns. In the meantime, our recent condensate wells are meeting or exceeding that tight curve from the condensate and cash standpoint, predominantly due to higher condensate yields.
Given the commodity price dynamic, we currently observed today an accelerated condensate production profile could very well become a meaningful way to increase our cash flow and well economics.
On the David Stalder Pad, where we drilled three Utica wells, two of which have average lateral length exceeding 14,000 feet, as well as the Marcellus wells was a lateral length averaging 9,200 feet. We continue to evaluate our Marcellus production. So far, these Marcellus wells are meeting or exceeding our expectations on Mcfe basis.
Our reservoir and geology team continues to evaluate production and pressure on these wells to fine-tune the Marcellus reservoir predictive model and ultimately estimate more accurate returns. My expectation is that, we will complete the evaluation in Q2 as a lack of analog data compelled us to rely on our own production history.
Pivoting to the Flat Castle project in Pennsylvania, we’re planning to spud our first Flat Castle well the PAINTER 2H in the next two weeks. Our Pennsylvania asset team is very busy with engineering and regulatory work to ensure that we have logistics and permits in place to hit full development cost structures when we stand up the rig line.
With this, I’ll turn the call over to Matt.
Oleg Tolmachev
Thanks, Oleg. For the fourth quarter of 2017, we again achieved solid revenue and cash flow generation, while continuing to manage our per unit cash operating expenses. Revenue for the fourth quarter was $104.1 million and our adjusted EBITDAX was $53.5 million.
For the full-year, we generated approximately $189 million in EBITDAX and 85% increase over the $102 million generated in 2016. This achievement was partially driven by improvements in commodity price, but also shows the importance of spreading at consistent fixed charge base across a larger volume of production and the importance of continuing focus on cost controls.
During the quarter, our all-in realized price was $3.59 per Mcfe before the impact of cash settled derivatives and firm transportation. Our natural gas price differential before transportation expense was negative $0.38 per Mcf. During the quarter, we’re able to take advantage of incremental unutilized firm capacity owned by other operators to receive a premium to Appalachian basis for our in-basin production. This capacity was on the REX and Rover pipelines and is likely to continue to be available as Rover can expand the capacity on its system. We continue to forecast that our Rover capacity will begin during the second quarter of 2018.
Based on our current production plans, we anticipate quickly filling that capacity and growing through it, as we move into the later – latter half of the year. We have assumed an increase in our annual operating expense guidance to account for the incremental transportation expense associated with the Rover pipeline coming online.
This increase should be offset with better pricing at the Gulf and Dawn Hub, where this production will then flow. As we can grow through this capacity, our transportation expense will decline as incremental production will largely flow to in-basin markets.
Our realized oil price during the fourth quarter was $49.61 per barrel and implies a negative $5.66 differential to WTI. We also achieved a full-year 2017 oil differential of $4.76 per barrel, which was significantly better than the tight end of our full-year guidance range.
As we look at our NGL sales during the fourth quarter, we realized a $31.16 per barrel NGL price equating to 56% of WTI. On a full-year basis, our realized NGL price was $23.62, that equated to 46% of WTI. This full-year realization was better than the high-end of our guidance range and was driven by the continued strength in propane price due to increased domestic use and growing export demand.
Moving to cash production costs, our per unit cash production costs for the fourth quarter were $1.49 per Mcfe. This included $0.34 per Mcfe in firm transportation expense. These expenses were higher on a quarter-over-quarter basis, given our income – increased liquid production in the quarter, as well as due to higher than anticipated workover costs. These workover costs impacted us by approximately $0.14 per Mcfe in the quarter.
For the full-year, we hit the low-end of our guidance range with strong per unit cash production costs of only $1.35. For the coming year, our cash production costs guidance range reflects the higher condensate and NGL production that we’re forecasting and the commencement of our Rover capacity in the second quarter. This increase in operating cost is more than offset by the increase in revenue anticipated from producing higher-margin products and selling our gas in higher-priced basins.
For the fourth quarter, our $32.3 million in capital expenditures consisted of $21.8 million in drilling completion capital, $4.6 million in midstream capital and $5.7 million in land capital. Capital expenditures for the full-year were $314 million under our guidance range when including approximately [Technical Difficulty] entered into late 2016. These figures include capital reimbursements that relate to our drilling joint venture with Sequel.
From a liquidity perspective, we ended the year with $208.6 million of liquidity. This consists of $17 million of cash and $191 million of availability on our undrawn revolving credit facility, after giving effect to $34 million of outstanding letters of credit. This liquidity position, coupled with our joint venture agreement provides us with flexibility and navigate the current commodity price environment, while allowing the company to grow cash flow and production.
We’ll continue to focus on means to further – of further enhancing this liquidity, as we move throughout the year and look to continue to grow top quality Appalachian business in the coming years.
On that note, Ben will wrap up our prepared remarks.
Benjamin Hulburt
Thank you, Matt. Innovation is at the forefront of our corporate culture with a shared belief that it will drive significant value creation over time for Eclipse as we continue to build scale. We have built an operating platform that has the ability to deploy cutting-edge techniques and leverages our best-in-class operating team.
The high degree of focus we have embraced on full cycle corporate level returns aligns our interest with our shareholders, allowing us to continue to properly navigate the current headwinds of the commodity price backdrop. And with the three-year plan we have put in place, along with the joint venture partnership with Sequel Energy, we maintain flexibility to manage our capital spend.
Operator, at this time, please open the phone lines for questions.
Question-and-Answer Session
Operator
Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Thank you. Our first question comes from the line of Holly Stewart with Scotia Howard Weil. Please proceed with your question.
Holly Stewart
Good morning, gentlemen.
Benjamin Hulburt
Good morning, Holly.
Oleg Tolmachev
Hi, Holly.
Holly Stewart
Maybe [Technical Difficulty] good job of outlining the difference between your corporate-level return and the wells level return, I’m getting some big feedback. I’m sorry. So can we just maybe talk about that balanced with Flat Castle, because obviously in your corporate level, you’re highlighting here that land is a big piece of that? So can we just talk about that versus or with Flat Castle and how you’re sort of balancing that versus your other projects?
Benjamin Hulburt
Sure, Holly. What we have embarked on is really a constant and iterative process, where we’re constantly looking back on starting at the wellhead IRRs with actual CapEx and actual timing, actual cash flows of the wells are into production and so on and estimating our IRRs the wellhead and then taking that down to corporate level by deducting G&A and hedges and land and so on.
From a land standpoint, what we have done this year that is reflected in the slide deck is we’ve taken the undeveloped acreage off of our balance sheet and use that to as the land component for those corporate level returns. Today, we’re – as of last year, that totaled about $6,900 an acre. So that’s what’s included in our current corporate level returns from a land component.
Flat Castle, where we paid $1,900 an acre, is not really reflected in go-forward returns yet, mostly just because it wasn’t closed by the end of the year. So that would bring down our weighted average cost of land probably to around $4,500 an acre. And it’s a great example over time that as we manage these things, we can improve those results and make them better and better and better.
G&A is another great example, because we don’t need to incrementally increase G&A as we continue to increase our production. So that gets better and better. It’s really causing every department in the company to focus on what is their impact into the returns of our wells.
Holly Stewart
Okay, great. That’s helpful. And then Ben, I think maybe mentioned that you had some just maybe sticking with Flat Castle there, there is some recent peer well that you are excited about. Is there anything there to highlight?
Benjamin Hulburt
Yes. Just looking at public data, there have been some recent wells from two operators adjacent to us that are in wells that are within, what we would call, the core of this sub basin. And they continue to confirm our initial type curve assumptions with very modest completion designs, which is something that we find very exciting.
In addition to that, we’ve been able to acquire full core in the area, which, if anything is probably causing us to look at the gas in place and reestimate it about 10% higher probably than we originally had estimated. So we continue to get more and more excited about this project area.
Holly Stewart
Okay, that’s great. And maybe just my final one on the Marcellus. I think, Oleg, you mentioned that you will complete your evaluation in – roughly in the second quarter. I’m assuming there’s nothing budgeted for another Marcellus well in 2018 at this point?
Oleg Tolmachev
That’s correct. There’s Marcellus – there hasn’t been a lot of Marcellus drilling in that area. So because of that, we don’t have a lot of analog data that we can look at to compare and ultimately estimate reserves. So before we put something out, we want to make sure we’ve got enough data that we’re confident in the conclusion and that’s just going to take sometime.
For example, we have no idea how really the condensate yields will change over time in this area the way we do in our Utica wells, where we have 300 wells in the dataset. So it’s just going to take some initial time. In addition, we have not dedicated the midstream components of the Marcellus to any midstream company at this point.
So that’s now that we’ve got some initial test data, we can lay out rig lines and projected production and so on and start working on the midstream plan, which from a proximity standpoint is relatively easy. There are several options close by. So all of that is in the work, so that we can begin to design that initial Marcellus rig line.
Holly Stewart
That’s, great. Thank you, guys.
Benjamin Hulburt
Thank you.
Operator
Our next question comes from the line of Mike Kelly with Seaport Global. Please proceed with your question.
Mike Kelly
Hey, guys, good morning.
Benjamin Hulburt
Good morning.
Mike Kelly
Ben, when I think about you guys, you’ve done a tremendous job of ratcheting up the project returns higher over the last few years longer laterals, more technology, I’d say returns stack up well versus anybody in any basin now. Your growth very compelling for the next three years and inventory has been significantly enhanced with this acquisition yet. The stock’s down 30% year-to-date, valuation is pretty cheap and it kind of, I guess, makes me think that it’s maybe the markets fear on the balance sheet side of things, especially with gas not having a three handle on it for the rest of the year? And just wanted to maybe have you walk through your comfort level with the balance sheet and maybe talk about any initiatives you have on really kind of on the balance sheet front? Thanks.
Matthew DeNezza
Sure. Well, I’d say, from a balance sheet perspective, as we sit right now, we’re very comfortable with it. However, one of the reasons, I think, we think we could trade better is by gaining additional scale. The market at this point, obviously, there’s a huge focus on drilling out of cash flow. Well, the problem is a small cap that’s extremely difficult to do and probably means you’re going to stay a small cap forever, if you restrict your activity level to that point.
So one of things we’ve got to do is continue to build scale, which obviously requires additional capital and additional sources and we don’t want to do that in a way that gets us in a bad leverage position as well. So it’s something, for example, the drilling joint venture was a great way to – for 2018 address that sort of issue. And that could be something that we continue to expand in the future in different areas or the same area and so on.
One of the things, we’re also looking at is in our current capital budget, we’ve got all our own midstream capital for Flat Castle and in Ohio within that budget. And we’re looking at ways of would that be better to outsource that and reduce the capital spend on that.
In addition to that, as we’ve said at the Analyst Day and we mean it is, we have the ability to reduce activity if we get to the second-half of this year and the gas price is what the front month is now of 260 or so, you will see us drop a rig as if the JV has expired and reduce that CapEx, which doesn’t really affect 2018 production, it obviously will have an affect on 2019 production. But can rather significantly drop CapEx even in 2018.
I guess, the only other thing I’d say is, it’s very early in the year. But because of our efficiencies, we’re actually projecting to be slightly below budget on CapEx even only after two months into the year. So we maintain a lot of flexibility in this plan without having long-term rig contracts and long-term take or pay contracts on the completion side and so on. So if the commodity price dictates it, you will see us make a change.
Matthew DeNezza
And Mike, it’s Matt. One thing that I just clarify with regard to Ben’s comment on the – just from a rig perspective is, effectively, our plan is – becomes a two net rig plan as we move into the fourth quarter because of that point we’ve drilled all the JV wells. And so, dropping a rig doesn’t really change our net activity relative to the first three quarters in the year. It simply doesn’t assume a doubling of effective activity net to Eclipse.
Mike Kelly
Got it. It was extremely helpful color. Just follow-up on that and just curious if you could quantify or ballpark it just how much of a swing in capital could represent outsourcing the midstream spend and maybe up in a JV, or just some sort of incremental JV, how should we think about that potential?
Benjamin Hulburt
This year in 2018, a third tranche on the drilling JV essentially means, we would stay at essentially one net rig for the whole year, which is what Matt was saying. And that probably reduces CapEx $50 million to $80 million depending on what our retained working interest is.
On the midstream side probably $10 million in capital in Flat Castle on the midstream side. But that becomes much more impactful in 2019, where it’s probably on the order of $60 million in capital.
Mike Kelly
Got it. Appreciate you guys.
Operator
Our next question comes from line of David Deckelbaum with KeyBanc. Please proceed with your questions.
David Deckelbaum
Hi, morning, Ben, Matt, and Oleg. Thanks for taking my question.
Benjamin Hulburt
Good morning.
Oleg Tolmachev
David Deckelbaum
And congrats on the first operator Marcellus wells. So I wanted to get some more color, one, just you said there’s a lot of local interest in building up a gathering. I guess, what’s the ideal structure? Is there – are there opportunities, is it just two simple acreage dedication? What would be sort of a non-capital endeavor for Eclipse for them just like a fee base?
And then I guess, on the drilling side just curious to hear that the contrast of drilling the Marcellus condensate area versus the Utica condensate that you guys have implied like a higher cost per foot and the well cost for Marcellus condensate and I recognize obviously it’s very early, but do you ultimately see that being below the Utica on a cost per foot basis?
Benjamin Hulburt
Sure. On the midstream side, I have to be a little careful, because this is actively being discussed. But we’re having discussions that run the gamut of different structures whether that’s a direct investment into a midstream entity that we would build and operate, whether it’s an outsourcing with an acreage dedication and so on. We’re actively discussing all of those options with several different parties. So I can’t go into too much, which way we think will be the best way to go at this point.
The – as far as the cost per foot on the Marcellus, again, not a lot of data, so we’re still doing a lot of initial estimates. But based on the lateral lengths that we think we would drill the Marcellus wells in the 14,000 to 15,000 foot laterals at this point, we expect that the cost per foot would be pretty much identical to our condensate wells in the Utica.
But again, it’s very, very early and a lot of testing to do still mostly on the completions design. These particular wells used quite a bit of proppant and it may prove that it’s not necessary to use that amount of proppant, which is what we’re finding in a lot of the Utica areas as well.
Oleg Tolmachev
David, I’ll just add to that a little bit what we had for our previously communicated Marcellus tight curve on the CapEx side was an 8,000 foot lateral assumption, or 10 at this point. But before we drilled these wells, we really didn’t know how the drilling operation would go. We have never done completions at 10,000 foot lateral length or above that.
And what we’re finding that geologically in this area of Marcellus is fairly quiet, very comparable to drilling the Point Pleasant condensate in Ohio. We have not had any issues placing in proppant. And based on some early reservoir analysis on PVT analysis, we don’t believe that drilling longer Marcellus area of wells in our area will be detriment to EURs either.
So that likely push us in the direction of drilling longer Marcellus wells, which will drive down our cost per foot significantly. So I would expect that our CapEx will go down on these wells. And then additionally, of course, when you drill in the two wells in the area out the door, you tend to go with a more conservative completions lots of sand and roughly overstimulating these wells.
So as we continue our reservoir evaluation of these wells, we will be tweaking our completions designs towards maximized IRR similar to what we’re doing in the Utica, where really we’re designing these wells individually based on condensate yields. And so coupled with that hopefully, we will get to a good understanding of the path forward in the next couple of months.
David Deckelbaum
I guess, how did the early days look in terms of liquids yields?
Benjamin Hulburt
The initial liquid yield is a little lower than we originally expected. Obviously, that means the gas is higher, but we don’t really know what that means over time yet and how does that yield change and so on. So it’s – but at least in the initial results, they are a little gassier than we had originally expected.
David Deckelbaum
Got it. And Ben, the last one for me was just, you discussed, I guess, and you harped on this at the Analyst Day, just the intention to become a little bit more liquids weighted. Is there sort of like a target that you have in mind like, say, a multi-year organic progression, or do you think that this is something that you need to sort of leverage your way into through some other acquisitions?
Benjamin Hulburt
We certainly have the organic ability to continue to increase our liquids component. And in terms of a – we don’t really have a stated goal right now with the two commodity prices and the outlook for the two more is better on the liquids front.
So – but we have the ability to grow that organically for awhile. At the same time, we’re constantly looking for areas, where we can apply what we’re really good at. And we did that with the Flat Castle area, which is obviously a dry gas inventory add in a fantastic project area. But – so now as we look at new ways to add for our inventory, we are more focused on the condensate portion, given that we already did a dry gas acquisition.
David Deckelbaum
I appreciate it. Thanks, guys.
Benjamin Hulburt
Thank you.
Operator
Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed with your question.
Ronald Mills
Good morning. Just to follow-up on the commentary that we just made in terms of proppant levels, seemed to have like a lot of people starting out with quite a bit of proppant and maybe tweaking down over time. I don’t know, any more color on what you were seeing on the proppant side in the early day results? What do you think are some of the more important factors in this productivity, whether it’s proppant versus cluster or stage spacing or well spacing on the data you’ve been able to gather so far?
Benjamin Hulburt
Great. Ron, before I turn it over to Oleg on that, I think, one of the key components of what we’re trying to communicate is, we are not just blindly following type curve assumptions in our drilling programs. So we’re individually tailoring each of those variables to what we think produces the highest rate of return. And whether that means a higher EUR or not, it what produces the highest IRR and there’s an interrelationship with each of those variables, proppant loading is just one of them.
So we have to use type curves for the public and for analysts to give some idea of what it is we’re up to. So we still have those out there. But internally, what we’re highly focused on is constant analysis to see, which toggle should we pull and change to produce the highest IRR rather than EUR.
Oleg Tolmachev
So echoing to Ben’s comments, we’ve talked a little bit about this in the Analyst Day presentation, where we have the examples of actual wells that – one of the examples is the pad we’re currently completing and one we’re going to spud on soon, where based on our very proprietary reservoir model and how it nets out condensate yields and other parameters, you can basically get to different types of the economic returns by varying intralateral spacing between the between the laterals, proppant loading and some other parameters. And that varies based on where you are in the condensate window very significantly. That also varies based on the commodity pricing and that also not the list of which that varies on our contractual structure for a simulation pricing.
And so with regard to whether we were going to see a less proppant or more proppant going forward, it’s very uniquely based on each well essentially. So one example, where we’ll look at a 4-well pad where our type curve suggests a slumping about 2,300 pounds of proppant per foot. We established that based on the spacing and based on the condensate yields and based on other reservoir parameters, actually the maximum economic returns would get you to at 1,600 pounds per foot proppant loading, which dropped almost $6 million of CapEx from the pad and gave us an additional 10% to 12% rate of return.
And so we’re really – are looking at each well in a very specific way, whether it’s a parent or child well inside, outside lateral, what is expected condensate yields whole breadth of parameters that really are affecting on our completion designs.
Ronald Mills
Okay. And moving to Flat Castle, in terms of the wells you’re referencing, in terms of recent industry wells, relative to your position, is it – are they located more to the South and East or more on the Western edge? I’m just looking at your Analyst Day presentation and where you look at the offset operator activity, just trying to get a sense as to where those new wells are and how it relates to the your existing position?
Benjamin Hulburt
Sure. They’re actually on both sides, the East and the West with different operators. Shell is the most active in the area and there to the East of us and then there’s drilling recent wells on the Western side that continues to both on the East and the West continue to actually move in closer and closer and closer to our acreage, which we – we don’t think is a coincidence, because that’s where the highest gas in places.
So it’s really a function of both, and we’re just pulling the public data. We don’t have any data sharing and have any nonpublic information on these wells. We’re just pulling the wells that have been posted with the State of Pennsylvania.
Ronald Mills
And have you seen any of – either of the other operators changing the way they’re drilling wells? I mean, are people starting to extend lateral lengths, or is your first well that you spud really going to be one of the first “super-lateral” up in that area?
Benjamin Hulburt
Sure. We’re not seeing the average lateral lengths in what we call the core of the play are still only about 6,600 feet and the average proppant loading is about 1,400 pounds. One of the interesting things is, we’re now – we’re seeing wells that are landed in both formations with virtually the same reserves or projected reserves at each formation, which is could be extremely interesting from a wine rack or dual zone potential.
We’re also seeing EURs from offset operators that are within our type curve band at 1,400 pounds per foot of proppant, which is substantially cheaper than what we have assumed in our type curve for the public, which assumes 2,600 pounds per foot. So again, we won’t blindly follow just stay at higher proppant levels, if they don’t incrementally add to the return.
And so we’re – from an economic standpoint, we’re getting more and more excited about this area as we learn more and more about it. We certainly aren’t at the point where we are ready to say we should go to a wine rack or we’ve got two formations. But there’s some indication that that is possible down the road.
Ronald Mills
Okay, great. And as it relates to Flat Castle was on the gas side you talked about having maybe wanting if you were doing something else, try to find a little bit more condensate two-pronged question and then I’ll jump off. Anything else in the Flat Castle area that is of interest, whether there’s tuck-ins or bolt-ons or similar opportunities like Travis Peake was? And then when you talk about condensate, are you basin agnostic or would you prefer to stick in kind of the Appalachian background?
Benjamin Hulburt
We definitely prefer to stick in Appalachia. There may be other areas in the country where we can apply what we do. But we do know Appalachia is the best and not just from a drilling standpoint, from a land standpoint, regulatory midstream and so on. So if we can stay in our home base that that’s our preference to do that.
As far as adding additional inventory in and around the Flat Castle area, there is the ability to organically lease and we are doing some leasing in the area. But frankly, adding major new inventory adds there doesn’t really address the company and how we need to grow. Our inventory is not really our issue at this point.
I think before the Flat Castle acquisition, we felt like we needed to add that additional inventory. But now that we have significantly adding to that dry gas inventory is probably not as accretive as some of the other things that we can do in terms of growing our scale and cash flow and so on.
Ronald Mills
Great. Thank you.
Operator
[Operator Instructions] Our next question comes from the line of Stark Remeny with RBC. Please proceed with your question.
Stark Remeny
Good morning, guys. Thanks for taking my call.
Benjamin Hulburt
Good morning.
Stark Remeny
So I guess, as you think about the initial production acceleration testing for the condensate window, do you have any, I guess, color around what your expectations are for the potential uplift? And then are there any infrastructure or other just constraints on whatever that max uplift could be?
Oleg Tolmachev
No, at this point, we don’t really have any specific expectations as to how much incrementally we can produce in a certain amount of time. The whole idea is to go through a thorough evaluation of DVT properties of these wells and really establish whether there is a deterioration of EURs as a function of more aggressive production profile. Is there some issues in the reservoir well cost changes in permeability that will decrease our IRR and things of that nature.
So the goal is to do so in a way to where it’s accretive the well economics. And certainly, a part of that discussion is looking at our midstream and marketing considerations and essentially not to create a surge in production that we have. We don’t know what to do with. And so it’s a very – it’s a complex discussion that’s both driven by our reservoir faults and midstream marketing as well. So – but we should be converging on the answer shortly.
Matthew DeNezza
This is Matt. As the CFO in the room, my guess would be just given the variability in that portion of the play and how we individually engineer and think about condensate yield variation in that portion of the play, that acceleration is going to be highly variable depending on kind of where you are East to West as well. So it’s probably even tough to just guesstimate just because of the variability you see depending on where you exactly are in that portion.
Stark Remeny
Okay, totally fair. And then in the prepared commentary, you guys talked about potential for further liquidity enhancement throughout the year, or in the coming years, is that – any commentary towards potential asset sales, or is that more on reserved base growth or something else?
Benjamin Hulburt
Yes, we don’t at this point have a lot of non-core assets. Anything we had that was non-core, we’ve pretty much divested over the last several years. Certainly, partnerships are always possible. The drilling JV sort of structure is one thing that we can continue or do one potentially even in the Flat Castle area. So that’s really what we’re talking about.
Stark Remeny
Excellent. Thank you, guys.
Benjamin Hulburt
Thank you.
Operator
Our next question comes from the line of Owen Douglas with Robert W. Baird. Please proceed with your question.
Owen Douglas
Hi. Good morning, guys. Thanks for taking the questions here. Just wanted to kind of touch on Slide 32 in the presentation, where you lay out your remaining locations. Just wanted to get a sense for when you – as you think about those locations and trying to achieve sort of a corporate level target return, do you have any sense for how that inventory stacks up? How we should be sort of thinking about it, given the current price deck?
Oleg Tolmachev
Yes. I mean, I think as we look at today’s pricing, I assume what you’re asking is relative to kind of the 355 scenario, what’s the return profile look like more on a strip base. know As you think about the Ohio Utica piece, certainly, a lot of the return numbers we show at 355, say that, given the accelerated profile, the dry gas is a little more – is higher returning.
I would say in a strip deck certainly that dry gas portion moves down and the condensate portion of the play moves up, which as we’ve talked about is kind of oriented towards where we’re producing. The interesting thing around the Flat Castle area right now what we show based on that base type curve scenario, which I’d remind people is assumes returns driven by costs that are oriented toward a much higher profit intensity than the wells that were utilized to produce the production curves that are going into that IRR calc.
I think, our hope and expectation to a large extent is that, that base return profile is not what we anticipate seeing when we drill these wells or this initial well. And so I would anticipate that that Flat Castle area certainly looks a lot more like the dry gas return accelerated scenario as we get some data under us.
And so I would say in the last piece obviously is the Marcellus area, where it’s a better early to tell. But if I just sit here and say, I’d probably focus, as Ben said, on condensate orientation first and then move into your dry gas areas. And then, as we know more about the Marcellus, that certainly becomes another area for condensate growth.
Owen Douglas
Well, actually, sorry, I guess I wasn’t clear on this one. I just meant in terms of showing that you have 300, so well, actually a lot of good information there. But it shows you used to have about 375 on remaining locations. But I was just trying to understand, if we were to be thinking about one that meets your corporate return objective and therefore try to back into what sort of drilling inventory you think you have that makes sense for you at the moment?
How does that look in sort of 16 years, which obviously a lot of those longer dated wells aren’t really kind of impacting much to evaluation. Just want to get a sense for how much is actually in that pipeline versus other stuff that potentially could be monetized?
Benjamin Hulburt
Sure. I mean, of our core locations that are listed there, at the tight curve assumptions, they would all meet our corporate level returns otherwise they wouldn’t be included on the list. Admittedly, the Marcellus is based on a lot less data and we still have to prove out and confirm all of our assumptions there.
I don’t think it’s something we would ever look to divest, because it’s up hole from our dry gas and that’s one of the unique things about the economics there, because all the infrastructure and pad and so on will be paid for by the Utica wells. So it’s kind of hard to just peel off that that one formation.
And then the rich gas locations, which I don’t have the slide in front of me, but I think there’s only a handful of them. Those are definitely going to be lowest on the list. If we did look to divest any acreage, it would probably be more in that area where we really don’t have much of a condensate yield. It’s more NGL-rich and it’s really the condensate that makes the economics so attractive. So it’s the rich gas area would be furthest out in our inventory.
Matthew DeNezza
Yes, those equates to about 5% of our total locations of the 375 you mentioned, 18 locations.
Owen Douglas
Okay, very helpful. And final one for me. Just in terms of thinking about your plan, so I understand that you guys are saying that in order to kind of realize the best efficiencies, you need to grow the scale of the company a little bit. How do you think about that relative to sort of liquidity sources? ABL’s are kind of tend to be available when you don’t really need them and when you need them sometimes are less available. Can you provide some sort of color in terms of your sort of liquidity sources?
Matthew DeNezza
Yes, I mean, certainly, I think when we look at our revolver it’s available, it’s not here – your long-term source of capital, right? So certainly, as we’ve touched on as a small-cap, you’re not going to ever – you’re not going to say, we’re not going to issue equity certainly. The price is a little tough given what we’ve talked about in terms of the market over the last couple of months.
The high yield markets open, we could do something there. But probably wouldn’t want to do it in size such that that impacted our leverage metrics significantly. And that as Ben has touched on throughout the call, some of these midstream options and joint venture options provide us with additional sources of capital and we certainly see those as open and available today.
Owen Douglas
Okay, great. Thank you very much, guys.
Matthew DeNezza
Thanks.
Benjamin Hulburt
Thank you.
Operator
We have reached the end of the question-and-answer session. Mr. Hulburt, I would now like to turn the floor back over to you for closing comments.
Benjamin Hulburt
We just like to thank, everybody, for their continued support and participating in call today. Thank you.
Operator
Ladies and gentlemen, this does conclude today’s teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.
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