Ranger Oil Corp (ROCC) 2019 Q1 法說會逐字稿

Good day, and welcome to the Penn Virginia First Quarter 2019 Earnings Conference Call. (Operator Instructions) Please note this event is being recorded.

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

Thank you, Steve. 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, our 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 3 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 and 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're currently running 2 rigs and 1 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 ample 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 to 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 a first quarter realized oil price of $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 cost of $11.67 per BOE and 11% improvement year-over-year. The growth in adjusted EBITDAX allowed us to improve our net debt to adjusted EBITDAX ratio to 1.6x as compared to 1.7x 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 2018.

Now looking at Page 5, we believe there are 5 keys to Penn Virginia's success. Starting with production growth. With the continuous 2-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 and assuming we maintain a 2-rig program, we expect production growth to moderate while yielding significant free cash flow over the next several years. Next is our focused on cost. 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 live within your means, and we see a path to free cash flow generation by the second half of this year along the 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 to our drilling program by adding 47 million barrels of proved reserves, driven largely by successfully derisking Area 2 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 2 year compounded annual growth rate of about 57%. Using SEC pricing of $65.56 WTI and $3.10 Henry Hub 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 within Eagle Ford. 95% of total spending will be directed towards drilling and completion with the balance focused primarily on enhanced oil recovery, facilities, pipelines and grassroots 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 2 North, which should account for a little more than 70% of capital, although the well count will be approximately equal between Area 1 and 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 in place is 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 provided details of our drilling inventory, breaking it down by Area 1, the 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 3 type curves to simply reflect the arithmetic average of our Gen 3 and later actual slickwater completions, removing any potential uplift from utilizing the latest completion design. For Area 1 the type curve parameter 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 2,900 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 it's 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 5 Area 1 wells completed with, what you could call, a Gen 5.5 design, which early data suggest the further EUR uplift of another 15%. Again now that's a small dataset with limited history but very encouraging results.

The summarized 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 in later slickwater completion designs. Our base completion design in Area 2 North is the Gen 4 design and the CapEx and type curve parameters reflect that. We've 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 5 wells with a Gen 5.5 completion or exceeding this revised type curve in early time. While we're very encouraged by the early time results, 5 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 pressured 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 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 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 3 of the last 4 wells in Area 2 South are producing above this revised type curve. But once again, these 3 wells constitute a relatively small subset of another small 7-well sample and the overall average is still the average. It 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 in economic returns competitive with Area 1, which we've successfully done and that has also been accompanied 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 of 517 lower Eagle Ford inventory locations, we are estimating the portfolio would 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 slide is that it 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 petrophysical data, seismic data, well logs and other downhole data more accurately mapped to subsurface geology of our acreage position. This allows us to generate a 3-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, and will be updated as new 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 move up in oil prices has benefited oil producers with WTI hovering around $60 per barrel. Penn Virginia is well positioned as the entirety of our oil production is sold into 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 $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 use 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're focused on 3 initiatives to keep LOE at low levels. First, we're continuing to implement our field-wide smart gas lift intermitter 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 $1.25 per barrel versus having to transport via truck. And third, we remain focused on maintaining contiguous acreage footprint. This allows us to build out our SWD system more cost effectively and reduces labor cost 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, if any, oil and gas pipeline build-out costs are borne by our 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 in 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 Philips 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. I'm going to walk you through the Penn Virginia value proposition over the next 4 slides, starting with production growth. To be clear, we're targeting getting to free cash flow primarily. So while production growth is obviously important, managing the timing of our drilling schedule and our completion schedule and their 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 leads us to slide 13 where we show our adjusted direct cash operating cost 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 onetime items, which is reconciled in the appendix of the presentation. That's begun from $14.41 per BOE in 2017, and we continued 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's focus on cost optimization is continuing to drive down expenses and 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 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 of the last couple of years. We have successfully driven our net debt to adjusted EBITDAX ratio down from 2.6x at year-end 2017 to 1.7x at year-end 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 1.5x 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 on 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 2019. 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 have 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 summarize the attributes that we believe makes Penn Virginia quality investment. With the continuous 2-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 oil-weighted E&P. Our proximity to waterborne markets allows Penn Virginia's to access premium-priced markets, access to Corpus Christi by truck and the LLS in 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 and 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.

And our first question comes from Jeff Grampp with Northland Capital Markets.

John, first I 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 towards an 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 neutral well?

Well, let's first talk about the CapEx portion of it. I think the $10 million that we allocated this year will cover most of the infrastructure. The one thing that it probably does not cover is the working gas volume that would be needed for the injection. We've identified at least 3 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 develop 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, that may aid it. But this area fits the bill for being mostly horizontally and vertically contained.

In terms of rate of return 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 1 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 meeting a minimum rate of return that would obviously -- we have to compete with other projects in the portfolio, but I think we target something at a minimum of 25%.

Okay. Great, great. Very helpful details. And for my follow-up, looking at that EOR map that you guys provided and you have all the PDPs and 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?

Yes. That's a good question, Jeff. I mean we've drilled -- I think to date, we got roughly 450, 460 producing wells or active wellbores. And then we've got over 500 remaining locations. So we're right at the 50% or so at -- being fully developed. But only 120, 130 of the most recent wells 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 hits from slickwater towards the hybrids turns out to be a positive thing. Now when it comes to offsetting slickwater with slickwater completions, 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 -- and some of this is speculation, so let me qualify it as such, but when you offset a slickwater well -- when you offset a hybrid well with the slickwater completion, the hybrid completions generally have longer frac lengths that don't fully -- as fully developed in near wellbore region as the slickwater, and we think that's why we're seeing positive frac hits. And 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.

Our next question comes from Irene Haas with Imperial Capital.

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 fewer 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 is that a function of different generation of completion?

Yes. So your first question is, I think the best way to answer it Irene is by combining locations that maybe would have too short laterals we get 1 with an XRL. So we would have 1 gross well where we previously would have 2. That gets further affected by our recent acquisition activity over the last couple years where our actual net working interest went up. So while gross well counts or stick count remain relatively flat due to drilling XRLs and increasing our working interest, our net account stabilizing going up. Does that answer that part of your question?

Yes. And the second part is the well cost a little bit higher than before.

Yes. And that's primarily in Area 1, we've committed to a base -- our base completion being at Gen 5. So at Gen 4, we had -- I think it was 200-foot stage spacing and Gen 5 is 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 cross creep on the drilling side and drilling the longer laterals sometimes takes a little bit longer than it would be, say, for a 6,000-foot lateral or 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 the time basis.

Okay. So kind of following up to your comment earlier. You guys have been fairly conservative with you ER because you 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 another 6 months, do you think the economics, be it, PV-10 and payout would look better because they will be hopefully by then apples-to-apples?

Yes. We certainly would hope so. Yes. 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, and I think that just reflects some of the wells in the last couple of quarters that didn't meet expectations. So to be fully transparent about that, we changed the type curves to reflect that accordingly. And I will allocate capital among the projects which make the most sense and has the higher return for us. 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 in the reserves from those wells before we allocate more capital to it. When we can get consistent returns and good growth on risk-weighted basis from our other 2 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 or early next year or with a couple of tweaks to the completion design to see what we can do to improve it.

And our next question comes from Richard Tullis with Capital One Securities.

John, Penn Virginia has done a good job of replacing its drilled acreage over the years, and it looks like you did the same in 2018. What was the average acquisition cost for that acreage last year? What opportunities do you see going forward in that?

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 acreage cost. We'd probably not want to release what we're paying for acreage out there in a competitive environment.

And 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?

No, we haven't really issued any 2020 guidance. I think the best bet to do 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 will be an ongoing maintenance cost 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's 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.

And then just lastly, John. I know that the oil cuts have been fluctuating several percent every quarter based on the number of wells, et cetera. But as you look out into -- over the next year or 2, what do you think the oil cut will average for you guys in the Eagle Ford?

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

Our next question comes from Lenny Raymond with Johnson Rice.

So last year you provided a strategic alternatives at the time you were evaluating corporate sale and merger and other business combinations or a strategic acquisition. So where do you all sit today following the termination of the DNR transaction? Are all those still in play?

Well, the reasons for the termination really revolved around market forces and shareholder opposition. Specifically, one of our shareholders made it loud and clear that he thought we were better off as a standalone company. So that's where we're at today. And we're a pure play only 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 in 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.

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

No, I think after this year on the 2-rig program, we're probably talking in the mid- to high single digits.

Our next question comes from David Snow with Energy Equities.

What is the experience of the other operators in the percentage increase in oil in place from enhanced recovery as opposed to primary?

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 2 ranges. Would say 40% to 50% uplift over primary.

Our next question comes from Dustin Tillman with Wells Fargo.

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, you also have a, I believe, 2022 term loan maturity. Can you just talk about how you're thinking about funding the business going forward now that we're talking about a more long-term business plan?

Yes. 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-lien 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 well as the design all along, we would like to refinance that and take out some of the credit facility at a point that makes sense.

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

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

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