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Penn Virginia Corporation (NASDAQ:PVAC)
Q1 2019 Earnings Call
May. 10, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good day and welcome to the Penn Virginia First Quarter 2019 Earnings Conference Call. All participants will be in listen-only mode. (Operator Instructions) Please note this event is being recorded.

I would now like to turn the conference over to John Brooks, President and CEO. Sir, please go ahead.

John A. Brooks -- President, Chief Executive Officer and Director

Thank you Steve, and good morning everyone. We appreciate your participation in today's call. I'm joined this morning by Steve Hartman our Chief Financial Officer; Ben Mathis, our Senior Vice President of Operations and Engineering; and Clay Jeansonne, Director of Investor Relations.

We will discuss non-GAAP measures on this call. Definitions and reconciliations of these measures to the most comparable GAAP measure are provided in our press release and the presentation posted on our website last night.

Prior to getting started, I'd like to remind you of the language in the forward-looking statement section of the press release, which was released yesterday afternoon. Our comments today will contain forward-looking statements within the meaning of the federal securities laws. These statements, which include, but are not limited to, comments on our operational guidance, and EURs are subject to a number of risks and uncertainties that could cause actual results to be materially different from those forward-looking statements, including those identified in the risk factors in our most recent Annual Report on Form 10-K.

Cautionary language is also included on Slide 1 of the presentation and we will use this presentation to go through today's discussion. Finally, after our prepared remarks, we will answer any questions you may have.

So, let's start on page three with a quick Company overview. Penn Virginia is a pure-play Eagle Ford Shale operator in Gonzales, Fayette, Lavaca and DeWitt counties in South Texas. We have approximately 84,200 net acres in the Eagle Ford, which is approximately 93 % held by production and 99% of which is operated by Penn Virginia.

Our estimated drilling inventory at March 31, 2019 was 517 gross in 444 net locations. Now I should point out this inventory count is only for the Lower Eagle Ford. One of our goals for our land team is to continue replenishing that inventory through organic acreage lease acquisition as well as acreage swaps with adjacent operators. We also hope to add value by identifying additional location inventory in the Upper Eagle Ford in Austin Chalk from our recently constructed Earth model, which is about 80% complete.

Our product mix in the first quarter was 88% liquids of which 74% was oil. Penn Virginia's oil production receives premium LLS or MEH pricing, which generates robust EBITDAX margins. We are currently running two rigs and one dedicated frac spread. We are targeting year-over-year production growth of 25% to 30% and we are well on our way to achieving that target based on first quarter results and April production, which is significantly higher than the first quarter average. We also reached what we consider a significant milestone in February, when our gross cumulative oil production surpassed the 50 million barrel mark.

Let's move on to Page 4 take a closer look at our solid operational and financial performance for the first quarter. Our first quarter 2019 production averaged 24,692 barrels of oil equivalent per day, which was a 53% increase from the same period last year. Looking specifically at oil, we grew year-over-year production by 47%. We benefit from our close proximity to the LLS and MEH markets, which resulted in the first quarter realized oil price $57.39. This was approximately $2.50 higher than, or 105 % of what WTI averaged for the first quarter.

Adjusted EBITDAX was $83.8 million, or $37.70 per BOE for the first quarter 2019, which was 66% higher than the same period last year. We recorded adjusted direct operating costs of $11.67 per BOE, an 11% improvement year-over-year. The growth in adjusted EBITDAX allowed us to improve our net debt to adjusted EBITDAX ratio to 1.6, as compared to 1.7 times at the end of 2018. Finally, increased production, lower cost and continued strong pricing drove adjusted net income per share up 52% to $2.25 per diluted share from the first quarter of 2008.

Now looking at page five. We believe there are five keys to Penn Virginia's success. Starting with production growth, with a continuous two rig program, we expect production growth of 25% to 30% this year and we expect to do it, while drilling within cash flow. Looking beyond 2019, in assuming we maintain a two rig program, we expect production growth to moderate, while yielding significant free cash flow over the next several years.

Next is our focus on costs. In this volatile commodity price environment to remain profitable, you must maintain a lean and low cost structure. We believe Penn Virginia has one of the lowest cost structures for an oil-weighted E&P. You also have to maintain strong margins, and as I previously mentioned, our close proximity to the Gulf Coast allows Penn Virginia to access premium priced markets. This includes accessing Gulf Coast waterborne markets including Corpus Christi by truck and the LLS and MEH markets through multiple pipeline access points.

And we want to ensure financial discipline, given the current and expected continued volatility in the energy commodity markets we remain laser-focused on maintaining financial discipline and a strong balance sheet. Growing production while drilling within cash flow is a great example of that. And finally, the most important measure generate free cash flow. Ultimately you must lived within your means and we see a path to free cash flow generation by the second half of this year along with significant free cash flow in 2020. We believe this makes Penn Virginia unique a proven small cap with solid production growth and a clear path to free cash flow generation in the near term.

Turning to Page 6. As we did not hold a fourth quarter conference call, we didn't have the opportunity to highlight what was an outstanding year with many successes in 2018. In addition to growing oil production by 120% and total production by 110%, we also created significant value through our drilling program by adding 47 million barrels of proved reserves, driven largely by successfully de-risking area to north with several impactful slickwater completions.

During 2018, we replaced 734% of our production and grew total proved reserves to 123 million barrels, a year-over-year increase of almost 70% yielding a two-year compounded annual growth rate of about 57%. Using SEC pricing of $65.56 WTI and $3.10 (inaudible) for gases, the company at year end had a SEC PV-10 of approximately 1.8 billion.

Turning to our capital budget for 2019 that is summarized on Page 7. Capital spending is currently estimated at $345 million to $365 million, all that in the Eagle Ford. 95% of total spending will be directed toward drilling and completion, with the balance focused primarily on enhanced oil recovery ,facilities, pipelines and grass roots acreage leasing. While our plans may evolve as we move through the program, we currently expect to drill approximately 40 gross or 35 net wells. We expect total spending to be weighted significantly to area to north, we should account for a little more than 70% of capital, although the well count will be approximately equal between Area 1 in Area 2 .

Looking to the future and beyond, the primary recovery stage of our reserves, offset operators are beginning to test pilots of enhanced oil recovery or EOR. You may think of EOR as water floods or CO2s and you'd be right, but EOR also includes natural gas injection. During the primary recovery stage of an Eagle Ford well only a small fraction of the estimated total oil and places recovered, leaving behind 80% to 90% of the original oil in place. Several EOR pilots are very near and on trend with our contiguous 84,200 net acreage position and we are excited about what EOR could mean for Penn Virginia moving forward. We currently have approximately $10 million allocated for EOR for 2019 and expect to begin our first EOR pilot in late 2019, or early 2020 with initial results in the second half of 2020.

On Page 8, we have provided details of our drilling inventory breaking it down by Area 1, Area 2 North, Area 2 South and the average of our portfolio as well by conventional laterals and XRLs. This inventory count is up-to-date as of March 31, 2019. Based on the results, we have seen so far, we are allocating minimal capital to Area 2 South for the balance of 2019.

So, let's talk about type curves. Overall we've updated and revised our three type curves to simply reflect the arithmetic average of our June 3 and later actual slickwater completions, removing any potential uplift from utilizing the latest completion design. For Area 1, the type curve parameters shown are quite simply, the arithmetic average of the historical performance of 58 wells completed with GEN 3, GEN 4 and GEN 5, slickwater completion designs.

The increase in CapEx is primarily attributable to moving to a GEN 5 completion design, which is now our base design for Area 1 and targets about 2900 pounds per foot of profit. The 10 wells in Area 1 upon which we've conducted Gen 5 completions appear to be exceeding this type curve EUR by approximately 6% in early time, but since its only a 10 well sample set with limited history, we're going to use the average of all 58 wells completed with GEN 3 or later, as our type curve. We also have another five Area 1 wells completed with, what you could call a Gen 5.5 design, which early data suggest a further EUR uplift of another 15%. Again now that's a small dataset with limited history, very encouraging results.

To summarize, the Area 1 discussion, this may be a conservative way to present our Area 1 type curve since it uses Gen 5 CapEx, against an average of a larger numerical set of wells that included earlier less productive outcomes. However, it is consistent with the methodology of using overall average results without any aspirational uplift.

In Area 2 North, the type curve parameters are also simply the arithmetic average of historical performance of 28 wells completed with Gen 4 and later slickwater completion designs. Our base completion design in Area 2 North is a Gen 4 design and the CapEx and type curve parameters reflect that. We have allocated approximately $15 million of CapEx in this year's budget to test Gen 5 and Gen 5.5 in Area 2 North, which is ongoing to determine, if we can achieve incremental well performance that is worth the additional expenditures. But again we have not included any aspirational uplift in these type curve parameters. Similar to Area 1, our most recent five wells with Gen 5.5 completion are exceeding this revised type curve in early time. While we're very encouraged by the early time results, five wells is not a very robust dataset and we'll stick with the larger dataset for the type curve for now.

In Area 2 South, the type curve parameters presented are once again simply the arithmetic average of the historical performance of 7 wells we completed with slickwater completion designs. So, it's a limited dataset for a limited period of time for a handful of wells. Area 2 south is deeper and higher pressure than Area 1 and Area 2 North.

And Gen 4 completion techniques utilized to date in Area 2 South have not been as successful as we would have liked. We also have some wells completed with Gen 5 and Gen 5.5 designs, but we want to obtain some longer production histories and fully evaluate our Area 2 South slickwater completions before allocating significant capital to that part of our acreage. To be clear, we still believe Area 2 South has significant oil in place, but given its challenging environment of being deeper, hotter, higher pressures, more work remains to be done to improve our completion design well performance and the economic returns.

The overall average of our Area 2 South results to date have not met expectations and we have revised our type curve for this area accordingly. At the same time, we're continuing to work on improving results and we do think we can improve results, as three of the last four wells in Area 2 South are producing above this revised type curve. But once again, these three wells constitute a relatively small subset of another small seven wells sample and the overall average is still the average. Should also be noted, Area 2 South consists of 41 locations out of our total inventory of 517 or about 8% of our total Lower Eagle Ford inventory.

Couple of years ago we had little or no proved undeveloped reserves at all in Area 2 and we set about with the goal of making Area 2's well performance and economic returns competitive with Area 1, which we successfully done, and that has also been a company with significant reserve growth. We now need to work to improve our Area 2 South performance to compete with the rest of our portfolio. Again it's a relatively small part of our asset, but we're confident we can improve overall performance, as recent results indicate at least in early time.

Based on the average of our total portfolio, a 517 Lower Eagle Ford inventory locations, we are estimating the portfolio will generate a rate of return of over 50%. The economics for this inventory will run at $60 WTI oil and $3 natural gas. Another takeaway from this line that is illustrates the value proposition of drilling XRLs, which is a more capital efficient approach to monetizing our inventory of net treatable lateral feet.

We are close to completing the first phase of construction of our earth model. As you may recall from prior discussions, the earth model combines better physical data, seismic data, well logs and other downhole data to more accurately map the subsurface geology of our acreage position. This allows us to generate a three dimensional view of the asset to help identify bypassed reserves, locate additional targets as well as guide our enhanced oil recovery pilots. This earth model is not a static model, however, it will be updated as new GEN data is generated. Initial results are promising and indicating additional prospectivity in the Upper Eagle Ford, where most of our technical efforts have been focused here early on. We believe this project could add additional future drilling location and as we get additional information, we will be sure to keep you updated.

Looking at Page 9. We believe Penn Virginia is one of the highest weighted oil companies in the E&P sector, with oil comprising 74% of our production stream, with an overall blended quality that averages approximately 46 degrees API gravity. The recent moveup in oil prices has benefited all producers with WTI hovering around $60 per barrel. Penn Virginia is well positioned as the entirety of our oil production is sold to the LLS or MEH market, which is currently trading at a significant premium to WTI. As I mentioned earlier, during the first quarter, WTI averaged $50.87 per barrel and our realized price was $57.39 per barrel, which is over $2.50 higher than WTI. As of yesterday, LLS is trading at more than a $8 premium to WTI and more than a $10 premium compared to Midland pricing.

Turning to Page 10. Penn Virginia enjoys what we believe to be one of the lowest levels of LOE per BOE in our peer group and E&P industry, especially given our heavy weighting to oil. LOE for the first quarter was a bit higher than the fourth quarter driven largely by seasonal effects and the increased used of chemicals during the winter months. You can see how the first quarter of 2018 was also higher than the balance of 2018 and we expect the same in 2019. We expect LOE to average between $4.50 and $5 per BOE for 2019.

We are focused on three initiatives to keep LOE at low levels. First, we are continuing to implement our fieldwide smart gas lift intermediate system. Currently 80% of our wells are on gas lift, which reduces downhole repairs and maximizes well uptime. Secondly, we also continue to expand our saltwater disposal system or SWD system. 30% to 35% of our produced water is transported via our gathering system. For every barrel of produced water, we transport on pipe, we save approximately a $25 per barrel versus having to transport via truck.

And third, we remain focused on maintaining a contiguous acreage footprint. This allows us to build out our SWD system more cost effectively and reduces labor costs by centralizing our workforce, which minimizes drive time and employee time to check and monitor our producing wells and assets. Also it should be noted that almost all of any oil and gas pipeline build out costs are borne by Midstream Partners and we have ample takeaway capacity with multiple marketing options for both our oil and gas for the foreseeable future.

Turning to Page 11. Unlike other basins in the U.S., the Eagle Ford has many crude oil delivery points and does not have pipeline constraints. Penn Virginia is an enviable position, as all of our production receives premium pricing that is either Louisiana Light Sweet or MEH. We have access to enterprise products in Kinder Morgan pipelines, which delivers directly into the Houston markets. We also have the ability to deliver crude to the Phillips 66 Refinery in Sweeney and truck oil to Corpus Christi to access waterborne markets. These factors are the primary reason, we are seeing crude realization of $2.50 above WTI.

Moving to Slide 12. Going to walk you through the Penn Virginia value proposition over the next four slides, starting with production growth. To be clear, we are targeting getting to free cash flow primarily, so oil production growth is obviously important, managing the timing of our drilling schedule and our completion schedule and the associated capital expenditures is critically important. To firstly, drill within cash flow and then generate free cash flow. That being said, we expect 25% to 30% production growth over 2018, based on our current plan. Our guidance for second quarter of 2019 is 27,000 to 28,000 BOE per day, and we expect full-year production of between 27,100 to 28,300 BOE per day.

That growth lead us to Slide 13, where we show our adjusted direct cash -- operating costs on a per barrel of oil equivalent basis. In 2018, we recorded $11.99 per BOE for our adjusted direct operating expenses. This is the sum of LOE, GPT, production and ad valorem taxes and cash G&A, adjusted for some one-time items, which is reconciled in the appendix of the presentation. And that's down from $14.41 per BOE in 2017 and we continue to improve on that number by lowering our cash cost to $11.67 per BOE in the first quarter of this year. For full year 2019, we expect between $11.25 and $12.75 per BOE. Our organization is focused on cost optimization is continuing to drive down expenses in our cash margins up.

Slide 14 shows our adjusted EBITDAX per BOE. For full year 2018, we generated $37.70 per BOE and matched that number in the first quarter. We've benefited greatly from lower cost and premium pricing, which is reflected in our cash margins. Importantly, we expect adjusted EBITDAX per BOE to remain at a high level for the balance of the year.

On Slide 15, we show you the cadence of the improvement in our financial position over the last couple of years. We have successfully driven our net debt to adjusted EBITDAX ratio down from 2.6 times a year in 2017 to 1.7 times a year in 2018. We saw further improvement in the first quarter of 2019, and expect the downward trend to continue with a targeted leverage ratio of less than 1.5 times by year end 2019.

Now slide 16, let's take a look at how we compare to certain of our small to midsize E&P peers. Other than for PVAC's historical results, this data is based on consensus estimates and peers' press releases, filings and presentations. I should note that we are not endorsing or confirming any of the consensus estimates or public data of our peers in the next several slides. You can see that based on this data, we had the highest EBITDAX per BOE ratio in our peer group during the fourth quarter of 2015. We also enjoy a strong financial position as compared to our peer group, and as I just discussed, we look for further improvement throughout 2019.

Turning to valuation metrics on the chart on the right within the Eagle Ford, consensus estimates at Penn Virginia trading at one of the lowest multiples for 2019 within that group of companies. With the growth I have laid out for you, the low cost structure, very strong cash margins and a clear path to free cash flow this year. We believe that Penn Virginia provides an attractive valuation.

On Slide 17, we summarized the attributes that we believe makes Penn Virginia quality investment, with a continuous two rig program, we expect production growth of 25% to 30% for 2019. And in this volatile commodity price cycle, you need to be profitable through all cycles. You must maintain a lean and low cost structure and we believe PVAC has one of the lowest cost structures for an oil-weighted E&P. Our proximity to waterborne markets allows Penn Virginia's excess premium priced markets access to Corpus Christi by truck in the LLS and the MEH markets by multiple pipeline access points helps to maintain our strong margins.

To survive and grow during turbulent times, you must maintain financial discipline and always preserve the balance sheet and we will continue to do so. First, you must live within your means, we see a clear path to free cash flow generation, by the second half of this year and significant free cash flow generation next year. We believe Penn Virginia is unique in the Small Cap space with production growth and a clear path to free cash flow generation this year.

And with that Steve, we can move to the Q&A portion of the call.

Questions and Answers:

Operator

Thank you. We will now begin the question-and-answer session. (Operator Instructions) And our first question comes from Jeff Grampp with Northland Capital Markets. Please go ahead.

Jeff Grampp -- Northland Capital Markets -- Analyst

Good morning guys.

John A. Brooks -- President, Chief Executive Officer and Director

Hi Jeff.

Jeff Grampp -- Northland Capital Markets -- Analyst

John, first wanted to get a little bit more detail on the EOR project that you guys are including in the CapEx budget. I think you said about $10 million is what you're looking to spend there. Can you kind of give us a sense of what does $10 million get you toward the EOR pilot program? And as you guys kind of see things today, understanding you haven't done your own pilot yet, but how do you kind of think about rate of return competitiveness versus a neutral well?

John A. Brooks -- President, Chief Executive Officer and Director

Well, let me first talk about the CapEx portion of it. I think the $10 million that were allocated this year will cover most of the infrastructure. The one thing probably does not cover is the working gas volume that would be needed for the injection. We've identified at least three areas that we want to start the pilot. The first area would probably be our -- is preferentially our best target it's fully developed. We've got it structurally quiet. So, we have vertical containment. We've got horizontal containment by the nature of the offset wells, which fully developed it.

So, we think that's a good place to start in terms of those metrics, as other parts of the asset that may be better suited just because it's shallower and lower injection pressures and other technical reasons that may aid it. But this area fits the bill for being mostly horizontally and vertically contained.

In terms of rate of return of what I -- what we said in the past is that, we would like to get to the point, where an EOR project will approximate the production growth associated with one rig, with the goal of reducing our overall capital burn rate, reducing our inventory drawdown, and arresting early time decline. So, I think we would want to target a meeting a minimum rate of return that would obviously have to compete with other projects in the portfolio, but I think we'd target something at a minimum of 25%.

Jeff Grampp -- Northland Capital Markets -- Analyst

Okay, great. Great. Very helpful details. And for my follow-up, looking at that, that EOR map that you guys provide and you have all the, that the PDP is in future locations and obviously some areas more developed than others. So, I'm curious if you guys are seeing any differing well performance drilling in some of those more developed areas, drilling I guess closer to legacy parent wells, or do you guys approach development any differently in those areas, versus maybe less developed acreage. And I guess in general just looking for some parent-child commentary from your observations.

John A. Brooks -- President, Chief Executive Officer and Director

Yeah, that's good question Jeff. I mean we've drilled, I think, today we've got roughly 450, 460 producing oils are active wellbores and then we've got over 500 remaining locations. So, we're right at the 50% or so of being fully developed. But only a 120 and 130 of the most recent wells are the are the slickwater wells and what we've seen historically is that the slickwater wells offsetting the hybrid parents generally outperform the hybrid parents. So, it's hard to quantify a parent-child interaction between that situation as being negative for the most part. Like I said I think 75% to 80% of frac heads from slickwater toward the hybrids turns out to be a positive thing.

Now when it comes to offsetting slickwater -- with slickwater completions and that's something that we have much less -- much limited data on. So, time will tell how that works, but I would expect that trend probably to continue. I think the -- in some of this is speculation, so let me qualify as such, but when you offset a slickwater well, when you offset a hybrid well with a slickwater completion, the hybrid completions generally have longer frac link that don't fully -- as fully developed the near wellbore region is a slickwater. And we think that's why we're seeing positive frac heads. I would imagine if we're doing the same thing with the slickwater, we'll be confining ourselves to the near wellbore region as well.

Jeff Grampp -- Northland Capital Markets -- Analyst

Got it. Got it. Really helpful details. And I will let someone to hop in.

John A. Brooks -- President, Chief Executive Officer and Director

Thanks.

Operator

Our next question comes from Irene Haas with Imperial Capital. Please go ahead.

Irene Haas -- Imperial Capital -- Analyst

Yeah, hi. I would kind of like to focus on Page 12 with your inventory, actually no, Page 8 for the inventory. Can you give me a little color as to what you guys have done differently? I mean it looks like you might have a few longer lateral as such, and in terms of total the well count went down in terms of gross well count, but it looks like the resource capture is pretty similar as before.

And then lastly, can you address the well costs slightly going up and instead a function of different generation of completion?

John A. Brooks -- President, Chief Executive Officer and Director

So, your first question is, I think, the best way to answer it Irene, is by combining locations that maybe would have two short laterals, we get one with an XRL. So, we would have one gross well, where we previously would have two. That get further affected by our recent acquisition activity over the last couple of years, where our actual net working interest went up. So, while gross well counts or stick (ph) count remain relatively flat due to drilling XRLs and increasing our working interest, our net account stabilizing go down. Does that answer that part of your question?

Irene Haas -- Imperial Capital -- Analyst

Yes. And then the second part of the well costs look little higher than before?

John A. Brooks -- President, Chief Executive Officer and Director

Yes. And that's primarily in Area 1, we've committed to base -- our base completion being a Gen 5 .

Irene Haas -- Imperial Capital -- Analyst

Okay.

John A. Brooks -- President, Chief Executive Officer and Director

So, at Gen 4, we've had I think it was 200 foot stage spacing and Gen 5 is a 172 foot stage spacing. So, you end up with more stages. So, that's probably the biggest jump in Area 1. And in Area 2, I think what we've seen is Gen 4 is the primary base design we're using there, but we have seen some cost creep on the drilling side and drilling longer laterals sometimes takes a little bit longer than it would be say for 6,000 foot lateral, 10,000 foot lateral, you still may get the most capital efficient way to develop it, but it can take a little bit longer on a time basis.

Irene Haas -- Imperial Capital -- Analyst

Okay. So, kind of following up to your comment earlier, you guys are being fairly conservative with your EOR because you're really looking at historic, the last few years you're not baking in any uplift that you would gain from having the newer generation. So, if we were to fast-forward this chart in another six months, do you think the economics the PV-10 and pay out would look better, because they'll be hopefully by then apples-to-apples?

John A. Brooks -- President, Chief Executive Officer and Director

You know, we certainly would hope so. We think this is the best way to reflect the most recent well results. As you noticed, we moved our production guidance down just a hair (ph) , and I think that just reflects some of the -- some of the wells in the last couple of quarters that didn't meet expectations. So, to be fully transparent about that, we change the type curves to reflect that accordingly, and we'll allocate capital among the projects, which make the most sense and has the higher return force.

That being said, we're not completely walking away from Area 2 South at all. It has some of the highest oil in place calculations that we have on our assets. But we want to make sure we have a solid plan in place to optimize the producibility and the reserves from those wells before we allocate more capital to it.

You know when we can get consistent returns and good growth on a risk weighted basis from our other two areas, those are naturally going to get the bulk of our attention. And we'll come back to Area 2 South, I think later in this year, early next year with a couple of tweaks to the completion zone and see what we can do to improve it.

Irene Haas -- Imperial Capital -- Analyst

Hey, great. Thank you.

Operator

(Operator Instructions) And our next question comes from Richard Tullis with Capital One Securities. Please go ahead.

Richard Tullis -- Capital One Securities -- Analyst

Thanks. Good morning. John, Penn Virginia has done a good job of replacing its drilled acreage over the years and looks like you did the same in 2018. What was the average acquisition costs for that acreage last year? And what opportunities go in to (Multiple Speakers)--

John A. Brooks -- President, Chief Executive Officer and Director

Well, I think we'd hesitate to put a marker out there because it's a competitive environment. I would say this, that in 2019 what we're seeing is a little bit more acreage available at higher prices and we're going to focus on probably some swaps with our nearby operators, before we go commit to some higher -- higher acreage costs. We'd probably not want to release, what we're paying for acreage out there in a competitive environment.

Richard Tullis -- Capital One Securities -- Analyst

That's understandable John. Going back to the enhanced oil recovery opportunity, looking out to 2020, with success what range of spending do you think enhanced oil recovery could account for in 2020?

John A. Brooks -- President, Chief Executive Officer and Director

You know we haven't really issued any 2020 guidance. I think the best bet to do, we would look at the capital that we have estimated for this first pilot at the end of this year, which is roughly $10 million, plus the cost of some working gas volume. And I think on a per pilot basis, those are probably good numbers. There'll be an ongoing maintenance costs associated with those, which we actually don't have firmed up yet, because we're still trying to determine if it's better to lease or purchase the compressors. And there is a huge spread on monthly operating cost depending on which way you go. So, we hope to have that ironed out by the end of the year and give you more information as we have it.

Richard Tullis -- Capital One Securities -- Analyst

And then just lastly, John you know, I know that the oil cuts have been fluctuating several percent every quarter based on a number of wells et cetera. But, as you look out into over the next year or two, what do you think the oil cut will average for you guys in the Eagle Ford?

John A. Brooks -- President, Chief Executive Officer and Director

You know I think we're targeting in the 70% to 76% range. We'd like to stay there and higher obviously is better. You know, if we -- as we drill the deeper wells in Area 2 North and even in Area 2 South, we'll obviously do a pick up a little gas. And that's not always a bad thing, especially if you -- if you have enough gas to provide your own working gas volumes for your EOR versus buying it off in interstate pipeline.

Richard Tullis -- Capital One Securities -- Analyst

All right, John. That's all for me. Thank you.

John A. Brooks -- President, Chief Executive Officer and Director

Thanks.

Operator

Our next question comes from Lenny Raymond with Johnson Rice. Please go ahead.

Lenny Raymond -- Johnson Rice & Co. -- Analyst

Good morning, guys. So, what's you all provided a strategic alternatives at the time we're evaluating corporate sale, merger and other business combinations or a strategic acquisition. So, where do you all sit today following the termination of the DNR transaction, or all those options still imply?

John A. Brooks -- President, Chief Executive Officer and Director

Well, you know, the reasons for the termination really revolved around market forces and shareholder oppositions. Specifically, one of our shareholders made it loud and clear that, he thought we were better off as a stand-alone company. So, that's where we're at today. And we, you know, we're a pure-play oily Eagle Ford player living within cash flow. And that's where we want to go. If we find ways to increase our footprint and grow our acreage position and production through an acquisition that we can make accretive across most, if not all fronts then we'll do that. But right now, we're not actively pursuing any strategic alternatives.

Lenny Raymond -- Johnson Rice & Co. -- Analyst

Perfect. And then on the guide, I appreciate the 2019 color. But looking ahead to 2020, as I'll move to more of the free cash flow for model, what can we expect production growth to be? I don't know if you are giving that at the time?

John A. Brooks -- President, Chief Executive Officer and Director

You know, I think after this year on a two rig program, we're probably talking in the mid-to-high single digits.

Lenny Raymond -- Johnson Rice & Co. -- Analyst

Okay. And that's all I've got today.

John A. Brooks -- President, Chief Executive Officer and Director

Thanks.

Operator

Our next question comes from David Snow with Energy Equities. Please go ahead.

David Snow -- Energy Equities -- Analyst

Yeah. What is the experience of the other operators and the percentage increase in more in place from enhanced recovery as posted primary?

John A. Brooks -- President, Chief Executive Officer and Director

Well, what's been published, I've seen ranges vary from a 30% to 70% uplift to a 20% to 60% uplift. So, what you see there, I would say is the midpoint between those two ranges, would say 40% to 50% uplift over primary.

David Snow -- Energy Equities -- Analyst

Okay. Yeah, OK. Thank you very much.

Operator

Our next question comes from Dustin Tillman with Wells Fargo. Please go ahead.

Dustin Tillman -- Wells Fargo -- Analyst

Hey guys, thanks for taking the call.

John A. Brooks -- President, Chief Executive Officer and Director

Hey Dustin.

Dustin Tillman -- Wells Fargo -- Analyst

A lot of questions have been answered. A lot of my questions have been answered. But can you talk about the balance sheet a little bit. You have a decently large revolver draw, you're not significantly levered, but you have the revolver draw yourself as a, I believe in 2022 turn maturity. Can you talk about how you're thinking about funding the business going forward? Now that we're talking about a more long term business plan.

Steven A. Hartman -- Senior Vice President and Chief Financial Officer

Yeah, Dustin this is Steve. We just redid our revolver this last week. We now have a $500 million borrowing base and we extended the maturity out to April 2024. So, we're in pretty good shape right now. As you know we have the $200 million second term loan in place. We're just watching the market to see when a good time to refinance that. We're under no pressure to do that. We can be opportunistic, but we're watching that. And as was the design all along, we would like to refinance that and take out some of the credit facility at a point that makes sense.

Dustin Tillman -- Wells Fargo -- Analyst

Great. Thank you.

Operator

I'm showing no further questions. This concludes our question-answer-session. I'd like to turn the conference back over to John Brooks for any closing remarks.

John A. Brooks -- President, Chief Executive Officer and Director

Well, thanks for your interest and participation in today's call. We look forward to talking to you again next quarter.

Operator

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

Duration: 0 minutes

Call participants:

John A. Brooks -- President, Chief Executive Officer and Director

Steven A. Hartman -- Senior Vice President and Chief Financial Officer

Jeff Grampp -- Northland Capital Markets -- Analyst

Irene Haas -- Imperial Capital -- Analyst

Richard Tullis -- Capital One Securities -- Analyst

Lenny Raymond -- Johnson Rice & Co. -- Analyst

David Snow -- Energy Equities -- Analyst

Dustin Tillman -- Wells Fargo -- Analyst

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