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Roan Resources, Inc  (NYSE:ROAN)
Q4 2018 Earnings Conference Call
March 19, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

See all our earnings call transcripts.

Prepared Remarks:

Operator

Good morning. My name is Christine, and I'll be your conference operator. At this time, I would like to welcome everyone to the Roan Resources Fourth Quarter and Full Year 2018 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions)

Thank you. Allison Gilbert, Head of Investor Relations, you may begin your conference.

Alyson Gilbert -- Head, Investor Relations

Good morning and thank you for joining our fourth quarter earnings investor conference call. We will start today with prepared remarks from Tony Maranto, Chairman and Chief Executive Officer; David Edwards, Chief Financial Officer. Also on the call available for Q&A are Joel Pettit, Executive Vice President of Operations and Marketing; and Greg Condray, Executive Vice President of Geoscience and Business Development.

Today's call will contain forward-looking statements that will describe our beliefs, goals, plans, strategies, expectations, projections, forecasts and assumptions. Please note that the Company's actual results may differ from those anticipated by such forward-looking statements for a variety of reasons, many of which are beyond our control. Additional information concerning certain risk factors relating to our business prospects and results are available in the Company's filings with the SEC, including the Company's Quarterly Report on Form 10-Q and any other public filings and press releases.

Roan does not undertake any obligation to update forward-looking statements made on this call. Please note, our audit release and financial statements discussed today are not yet completed, we believe (ph) such information is subject to change as we complete our annual audit process.

Finally, we will refer to certain non-GAAP financial measures. For a reconciliation of these measures to Generally Accepted Accounting Principles, please refer to our fourth quarter press release or slide presentation that will be posted on the Company's website at www.roanresources.com.

I will now turn the call over to Mr. Maranto. Tony?

Tony C. Maranto -- Chairman and Chief Executive Officer

Thank you, Alyson, and thank you to everyone that has joined us for today's call. We appreciate your continued interest in Roan. 2018 was a critical year for Roan where we stood ourselves up as an independent public company and dramatically increased production. But 2018 was also a year where we learned a lot of very valuable lessons that will allow us to improve upon our unique and emerging asset in 2019. I'm excited for us to take all the learnings from 2018 and apply them moving forward.

Before getting into why we are excited about 2019, I'm sorry, before we are -- before getting into why we are excited about how 2019 will be a transformative year for Roan, let's recap how we ended 2018 and remind people about the unique scope and scale of our asset in the core of the Merge. I will start with the Roan snapshot on slide three that shows fourth quarter net production of 54,100 Boe per day, 27% oil and 31% NGLs. That is a 16% increase quarter-over-quarter and 110% increase year-over-year.

As you can see, Roan's asset consists of approximately 172,000 net acres that is positioned primarily in the Eastern Oil rim of the Anadarko Basin. The core of our asset is in the Merge area where we have the predominant leasehold position. We have approximately 115,000 net acres, giving us the potential to operate approximately 234 sections, most of which will be multi-sectioned units. As the map shows very clearly, it is an impressive block of contiguous acreage dominated by Roan.

Our year-end 2018 proved reserves are 306 million barrels of oil equivalent, up 32% over year-end 2017. This represents a PV-10 value of over $2.1 billion. We ended the year with eight rigs, but dropped to four rigs by the end of January, which is our current activity level. Dave will go through the details of that later, but we maintained a well-capitalized balance sheet with significant financial flexibility. We exited the fourth quarter with a 1.4 times annualized leverage ratio, and as you can see, we're well hedged for 2019.

On this map, you will notice a red line that represents our interpretation of where the Woodford Shale transitioned -- transitions into what is referred to as the peak oil generation and expulsion window. We will discuss this further on the next slide, before we go there, I'd also like you to take note of the outlined acreage position of the major operators in the Merge area. We are offset by large and very successful operators, and as you see on the map, our acreage overlaps Continental and EOG among others, where we have non-interest in there, where we also have non-operated interest in their wells. Roan's core asset is very well-positioned along the core trend of the Merge, SCOOPs play.

Slide four gives more color on basin quality. The most integral component defining the Merge area as an outstanding reservoir is the source rock maturity and reservoir quality of the Woodford formation. As you well know, the Woodford formation is the primary source rock in the Anadarko Basin. Across the vast majority of our acreage, the Woodford is in excess of 100 feet thick, as you can see on the far left map, and has very good reservoir properties, which results in the Woodford being a primary drilling objective for us, along with the Mayes formation.

One of the most important component is the thermal maturity of the Woodford, which essentially measures whether the source rock is capable of generating and expulsing hydrocarbons. The expulsion of hydrocarbons from the Woodford formation is how other formations are sourced. The middle map on this slide highlights how the Woodford formation maturity increases as you move West and deeper into the basin. The red line signifies where the Woodford formation has transitioned into the peak oil generation and expulsion phase or commonly referred to as the peak oil window. The vast majority of Roan's acreage falls west of this line.

The last map on this slide is the Source Potential Index. It is a calculation that combines the Woodford thickness and the Woodford thermal maturity into one attribute. In our case, the Merge has the right ingredients, source quality, maturity and thickness to generate a liquids-rich hydrocarbon product, and Roan's acreage is positioned optimally in this petroleum system sweet spot.

Moving to fourth quarter and full-year results on slide five of the presentation. Fourth quarter adjusted EBITDAX was $88 million, an improvement of 15% over the third quarter. For the year, adjusted EBITDAX was approximately $300 million, which is up 200% year-over-year. Again, fourth quarter production came in at 54,100 Boe per day, our highest to-date with oil production up 25% over the third quarter. Notably, since the formation of Roan, we have been able to materially increase the oil cut of the Company as the contributed assets from our predecessors were exhibiting oil cuts around 20% at the time of contribution.

For the year, production averaged 43,700 Boe per day, up approximately 170% on an equivalent basis over 2017 and oil production was up approximately 200% year-over-year. We drilled 26 gross operated wells in the fourth quarter for a total of 92 for the year. We averaged 6.5 rigs for the year and ended the year with a drill rate of over 14 wells per rig per year. We also brought 20 gross operated wells online during the fourth quarter for a total of 78 gross operated wells turned to sales for the year.

I will provide more details on well performance and our key learnings to be applied in 2019 shortly. In late December, because of falling oil commodity prices, we made the decision to halt completion activities. We made this decision for two basic reasons; one, used the break to reset our stimulation cost; and two, a break would allow us more time to study our recent completions and flowback initiatives to best optimize the 2019 drilling program. This has allowed us to project completed well cost for 2019 to be $7.5 million for a two-mile lateral, $1 million lower than our 2018 AFE.

Exiting 2018, we had 33 drilled and uncompleted wells that will be very capital efficient dollars for 2019, and are targeting to get to a normal working backlog by mid-year 2019. During the first quarter, we also executed a Water Services Agreement with Blue Mountain Midstream to manage our water needs in Central Oklahoma. We project this agreement will save the Company approximately $8 million in 2019 alone and more than $10 million on an annual basis.

Slide six is a key slide as it highlights optimization initiatives for the 2019 program based on results from 2018. We ran an aggressive program in 2018 ramping to eight rigs and learned a lot from all the wells we drilled, and those learnings will be applied to better optimize our 2019 program. As with all Tier 1 resource plays, there is a learning curve to take the play from emerging to a fully developed play, the Merge is no different. While ramping to eight rigs during the year, we had not built a sufficient inventory of permitted high graded drilling locations. To supplement the drilling inventory, we were forced to drill some locations that were previously permitted by our predecessors and some of those were testing more fringe non-Merge acreage and were not optimal drilling locations.

This is a common practice of a Company testing play limits, so this is not meant to discourage -- disparage our predecessors. This resulted in some varied well results that were less than optimal. We also drilled a couple of locations where we didn't have 3D seismic coverage that also resulted in less than optimal results. The results of the 2018 wells have helped us better delineate our highest value areas and really high grade our 2019 drilling inventory. We now have 3D seismic coverage over all of our locations to be drilled in 2019, so we have minimized that risk.

Another learning from 2018 was that the frac barrier between the Mayes and the Woodford is not uniformly present throughout the play. This lack of a consistent competent frac barrier resulted in significant communication between payers of Mayes and Woodford wells, with the Woodford well being the one that was negatively impacted. With the understanding of the Mayes and Woodford behaving as one flow unit over part of our Merge footprint, we've redesigned our co-development to account for this. While some of the results in 2018 did not optimize capital efficiency, the lessons we've learned allowed us to understand the reservoir and better evaluate and de-risk our acreage. With the gained knowledge in 2019, we will eliminate the poor performing wells, which points toward a drilling program with the projected PVI of 1.7.

One final point to make on this slide is our 2019 program will entail us doing frac preloads. Late in the year, we began testing frac preloads on fourth quarter wells, whereby we pressured up offsetting wells in advance of completion practices and we are encouraged by these initial results.

Speaking to fourth quarter wells, slide seven is the complete list of the results of all the wells turned to sales in the quarter. We had four wells where co-development of the Woodford and Mayes were improperly executed, and we noted those separately, so you can see how the program looks when it is optimized. All 20 wells had an average peak 30-day IP of 1,080 Boe per day, with 50% oil, 21% NGLs and 27% gas, when normalized to a 10,000-foot lateral. The average peak 90-day IP of these wells is 906 Boe per day, 50% oil, 21% NGLs and 29% gas, again, when normalized to a 10,000-foot lateral. After removing four wells that were improperly co-developed, the 16 more optimally produced wells had an average peak 30-day IP of 1,265 Boe per day and a peak 90-day IP of 1,055 Boe a day, also 50% oil, 21% NGLs and 29% gas when normalized to a 10,000-foot lateral.

On slide eight, we compare the fourth quarter wells that oil production performance to the wells drilled earlier in the year. Based on these data sets, you can see on this side that oil production from the fourth quarter wells is actually higher at both 30-day and 90-day, and oil production on the fourth quarter wells is declining at a slower weight compared to the other wells. This is a direct correlation between where we drilled our wells and our commencement of flowback management -- flowback pressure management on this well set.

In 2018, I've spent a lot of time in these presentations to beat the drum on wells targeting. We did and still do consider proper well targeting to be the first step in superior well results. Starting today, I want to discuss the importance of pressure managed production. As much as targeting, the attention paid to constantly monitoring flowing bottom hole pressure becomes your ability to keep your reservoir fluids above the bubble point pressure of the crude. This is the key to keeping gas and solution, and therefore, keeping the reservoir charged and producing crude longer. Successful results from this type of pressure management aren't seen until at least 90-day rates when it is noticeable that wells exhibit shallower declines and the cumulative oil production is higher.

On slide nine, you can see two visuals of this. The top chart shows an example of how pressure managed well rates do not decline as quickly and the bottom chart shows how cumulative oil production on pressure managed wells cross over and become greater. The end effect of this practice is to drive increased oil recovery, stabilized GOR trends and ultimately improve well economics. Results have confirmed our school of thought and you will see even more improvement as we pressure manage all of our wells in 2019.

Moving to our current thoughts on inventory. We began testing unit development in 2018 and came to a new conclusion based on the results from the units we operated and the units we participated in. We have determined that an appropriate conservative average number of wells per unit is going to be approximately eight wells, which we believe drives the proper balance between maximizing capital efficiency on a per well basis and unit net present value. This very conservative assumption provides over 1,300 remaining premium locations with an average lateral length of over 1.5 miles.

Furthermore, as I stated earlier, one of our 2018 lessons learned is our approach to vertical inter-formation configuration between the Mayes and the Woodford. We believe these reservoirs need to be developed simultaneously and staggered, not stacked, to achieve best results. As you can see on the map on slide 10, the bulk of our acreage is prospective for both Woodford and Mayes, with over 1,300 premium locations, we have well over 15 years of drilling at our current pace of approximately 60 to 70 spuds per year. We fully plan to add to this inventory level each year as we test other formations and add acreage.

With that, I will now turn the call over to our CFO, David Edwards. David?

David M. Edwards -- Chief Financial Officer

Thanks, Tony, and thanks to everyone that is on the call today. Speaking of fourth quarter results, we released certain key fourth quarter quarterly metrics earlier in February, which included production of 54,100 barrels of oil equivalent per day for the quarter, which is in line with our earlier fourth quarter of 2018 guidance. Oil volumes were 14,800 barrels per day or 27% of total production, which is a 25% increase from the previous quarter and 139% increase from the fourth quarter of 2017. Finally, oil and NGLs combined were 58% of production, marginally higher than our fourth quarter guidance.

Oil prices averaged $57.27 per barrel for the quarter, approximately $1 below index prices, highlighting the benefit we received with our proximity to Cushing and local refiners in the limited logistical burdens we incurred. Realized gas prices averaged $2.18 per Mcf, as compared to average Henry Hub prices of $3.69, which incorporate deducts of approximately $0.85 for regional pricing and $0.65 for gathering, processing and transportation.

Finally, we realized NGL prices of $14.90 per barrel or approximately 26% of WTI. This is an approximate 29% sequential decrease in NGL pricing as a result of two factors. First, NGL prices retreated in the quarter in line with general energy macro trends. And secondly, we converted from ethane rejection in the third quarter to ethane recovery in the fourth quarter, which results in a lower realized price per barrel.

Lease operating expenses for the quarter were $17 million or $3.51 per Boe. This amount was higher than expectations incorporated into our guidance, primarily due to increases in water disposal costs, which resulted from increased volumes from our upsized completion testing and general pricing trends in water disposal markets during the period. As Tony noted, we expect our water service contract with Blue Mountain Midstream to considerably reduce our operating expenses. Blue Mountain will commence services in the second quarter of 2019.

Production taxes were in line with projections and G&A was at the low end of expectations. For the quarter, G&A was $10.6 million or $2.14 per Boe after excluding equity compensation costs related to corporate reorg and bad debt expense. Incorporating these components, adjusted EBITDAX for the quarter totaled $87.8 million, a 17% sequential increase and 100% increase from the fourth quarter of 2017. CapEx for the quarter amounted to $217 million in the quarter, in line with our fourth quarter guidance. CapEx for the quarter included 26 gross and 19 net spuds and 20 gross and 16.5 net completions.

Finally, adjusted net income for the quarter amounted to $26.2 million. We continue to believe that our ability to consistently generate adjusted net income is unique for our peer set and speaks to the quality of our asset base and capitalization of the Company. As a result, we can demonstrate attractive corporate returns to the equity level. Specifically, our ROE and ROCE for the annual 2018 periods were 9% and 6.6%, respectively.

On slide 11, we outlined our 2019 guidance plan. As previously released, we have modified our previous plans issued in mid-2018 and scaled back on activity to adjust for declining oil price and ultimately to work toward generating cash flow sooner by the end of the year versus original projections of 2020. This plan is predicated on approximately four active rigs for the majority of the year, which drives production growth of approximately 20% from the fourth quarter of 2018 to the fourth quarter of 2019, and importantly, sets up the fourth quarter of the year to be positive cash flow. We expect that we can achieve this plan and exit the 2019 period with an LQA leverage ratio of roughly 1.5 times, in line with our current leverage.

I would like to discuss the anticipated results of the first quarter. During the first quarter, we transitioned our development activity from our 2018 run rate to our 2019 plan, reducing our rig count from eight rigs in January to four rigs in February. As a result, we expect to spud 13 gross wells. Additionally, as mentioned in the fourth quarter pre-release, we took a pause on completion activity around the turn of the year in an effort to allow pressure pumping prices to reset and optimize the completion design for the 2019 program.

We recommence completion activity in mid-to-late January with three frac crews operating, which is expected to result in the completion of 20 gross wells during the quarter. We have resumed normal operations and production is coming back online this month.

We currently expect first quarter production to exhibit a decline in production as compared to the fourth quarter for two primary reasons. First, natural gas and NGL price dynamics in the first quarter led us to elect into ethane rejection for the month of January, which is a revenue enhancing decision, but negatively impacts reported Boe volumes by approximately 1,600 Boe per day for the related period.

Secondly, the pause in completion activity around the turn of the year results in a substantial period in the first quarter where no new wells were brought first sales. This was exacerbated due to the lag effect of getting our first quarter completed well sets for sale based on a combination of completing multi-well pads, changes to our flowback sequencing of these pads as we manage interformation of co-development (ph), weather delays impacting completion services and delays getting wells connected to pipeline. As a result, we only expect 15 gross wells to hydrocarbon first sales in the quarter. This timeline in well set -- will be heavily weighted toward the end of the quarter, and as such, the 15 wells coming to first sales will -- in the quarter will average approximately 10 productive days in a quarter. As such, the contributing production from the development wells in the first quarter will be limited. Despite these deferrals of the first quarter development wells, we are maintaining our previous 2019 guidance targets.

On slide 13, we highlight our year-end 2018 reserve amounts. As indicated, our PDP base increased 51% from the prior year to 120 million barrels of oil equivalent, which equates to a value of $1.1 billion at year end 2018 SEC pricing. Total proved reserves increased 32% to 306 million Boe in an SEC PV-10 value of $2.1 billion. As noted on these slides, these metrics equate to a reserve replacement ratio of 468% and based on the (inaudible) of the PUDs, cost forward F&D amounted to $6.71 per Boe.

Turning to slide 14, we highlight our year-end capitalization table, which illustrates the net debt position of $508 million. Our fourth quarter credit metrics include LQA leverage ratio of 1.4 times for the quarter. As illustrated on the bar charts to the right, we show our credit metrics in the context of the peer set. Notably, we consider this peer group to be among the better capitalized companies in the small mid-cap upstream space and we continue to rank as one of the better credit profiles in the set. We want to bring your attention to one other credit metric, which is our asset coverage ratio. Based on year end 2018 PV-10 of approximately $2.1 billion at SEC prices, we are approximately 4.1 times covered, which ranked us one of the best in the industry.

Finally, we noted our liquidity position of over $240 million based on year-end net debt and our recently increased borrowing base of $750 million -- to $750 million. This liquidity position more than adequately funds our 2019 development plan as we work toward generating positive cash flow in fourth quarter of 2019. Despite this comfortable liquidity position, we may look to opportunistically term out a portion of our borrowing based debt in the first half of 2019.

On slide 15, we have outlined our hedge position. We maintain an active hedge program through the 2018 period, which has positioned us well for the general softening of energy commodity prices. Specifically, based on our 2019 guidance midpoint, we have 90% of our 2019 oil production hedged at an average price of approximately $60 per barrel and 80% of anticipated gas production hedged at $2.91 and 16% of NGL production hedged at $32 per barrel. Additionally, approximately 71% of our natural gas loss are hedged with basic swaps.

With that, I will turn the call back over to Tony for closing remarks before we start the Q&A session.

Tony C. Maranto -- Chairman and Chief Executive Officer

Thanks, David. I would like to end the call by reiterating how excited I am to be at this point in this Company's life cycle. We are at a place where we can grow production materially in 2019 and generate free cash flow by the end of the year. That is pretty remarkable considering we have only been a stand-alone Company for a little over a year. We will able to -- we will be able to take all the advancements we made in 2018 and apply them to 2019 and beyond. I truly believe 2018 was a transformative year for Roan and 2019 will be a year of increasing value for our shareholders.

With that, operator, we are now ready for questions.

Questions and Answers:

Operator

Thank you. (Operator Instructions) Your first question comes from the line of Derrick Whitfield from Stifel Financial. Your line is open.

Derrick Whitfield -- Stifel Financial -- Analyst

Good morning all and congrats on your progress in 2018.

Tony C. Maranto -- Chairman and Chief Executive Officer

Thanks, Derrick.

Derrick Whitfield -- Stifel Financial -- Analyst

With regard to your comments on the four wells that were negatively impacted by improper Mayes and Woodford co-development. To what degree can you overcome the lack of a competent frac barrier in those areas through optimized completions and sequence flowback (ph)?

Tony C. Maranto -- Chairman and Chief Executive Officer

Derrick, the lack of a frac barrier really can't be overcome. So what that forces us to do is, and that's kind of what we mean by the term co-development, is put enough offset between the interformation wells, the Mayes well and the Woodford well, so that you can have independent frac jobs and allow the two wells to produce independently. So, from our standpoint, it wouldn't be cash efficient for us to go out and do a lot of work testing barriers. It's -- to me it's just the more prudent thing to do just to incorporate into your development thoughts that there is no frac barrier there and adjust your spacing accordingly.

Derrick Whitfield -- Stifel Financial -- Analyst

That makes sense. And then, regarding the other 16 wells announced during the quarter, would it be safe to assume that they are representative of what you'd expect to achieve in 2019 assuming optimized D&C and flowback techniques?

Tony C. Maranto -- Chairman and Chief Executive Officer

From a general standpoint, Derrick, yes. Those wells were probably skewed just a little bit more to the oilier part of the region. But as we study wells across the entire footprint, we see no reason why the results that we see here aren't -- we shouldn't be able to show across the entire footprint. Again, especially with -- make sure the wells are targeted properly and produced properly.

Derrick Whitfield -- Stifel Financial -- Analyst

Thanks. It's very helpful. Thanks for your time.

Tony C. Maranto -- Chairman and Chief Executive Officer

Thanks, Derrick.

Operator

Your next question comes from the line of Ron Mills from Johnson Rice. Your line is open.

Ronald E. Mills -- Johnson Rice -- Analyst

Good morning, Tony.

Tony C. Maranto -- Chairman and Chief Executive Officer

Good morning, Ron.

Ronald E. Mills -- Johnson Rice -- Analyst

I think just on the co-development, just as we think about the difference between the Mayes and the Woodford in type curves, I see, with you -- when you have the three, six, and nine-month data, you start to see the curves cross over kind of within six months on a cumulative basis. But given the new pressure management regime, how would you think about adjusting type curves or what do you think type curves look like over time versus what you had originally put out? And do you think there's much appreciable difference from our product mix versus what was originally advertised?

Tony C. Maranto -- Chairman and Chief Executive Officer

Several things there, Ron. And let me take the question as to type curves first. No, we didn't really update our type curve here. We put a lot of thought into it as to how should we do this, because you're right on several points. One is pressure management does change the shape of the type curve, right? The slide that we've got in the deck that kind of illustrates that is -- it will generate -- the type curve will generate slightly lower IP-30 rates, but eventually cross the time -- cross -- on a cumulative basis, crossover at some point where you're actually producing more oil over time, which is the whole goal of pressure management is to produce more crude, which is the -- still the highest revenue driver we have. But we need more data first of all. So we tend to more look at this as -- and the slide that we have in there with all the well results from the fourth quarter has continued to show you guys continual IP-30, IP-60, IP-90 and even IP-180 when we get to that point, so that the type curves kind of become more apparent to everyone over time and kind of from our standpoint, makes us the most transparent.

Ronald E. Mills -- Johnson Rice -- Analyst

Okay. And moving on to the inventory comments, when you talk about eight wells, is that -- per section, is that eight wells spread across the Mayes and the Woodford, or is it kind of four and four, will it depend on where you are across your acreage and whether or not there's a frac there, I'm just trying to get a sense as to how that number came or was arrived at?

Tony C. Maranto -- Chairman and Chief Executive Officer

Yeah. Good question, Ron. It's driven by several different factors. One is just an average. When you look at our footprint from these east to west, not only as I said a little earlier, you deepen going into the basin. So you have different GORs as you go from east to west, you also have different thicknesses in both intervals as you move from east and west too. So, thickness really drives what your ultimate spacing is, because more thickness just means more hydrocarbons to pull from.

Yeah, we are co-developing these units. So the eight wells that we talk about is eight across those benches. I wouldn't characterize it as really being four and four, because each unit is a little different. The exact placement of wells depends on the thickness of each interval in each unit, which going back to the type curve question, that's also really drives -- we're driving ourselves now on type curves per unit, because we see that's just the way that -- the best way for us to handle it. So it is an average number, it is across those benches and it will -- it's variable in each unit, depending on the thickness of each formation.

Ronald E. Mills -- Johnson Rice -- Analyst

Great. Thank you. I'll let somebody else jump in.

Tony C. Maranto -- Chairman and Chief Executive Officer

Thank you, Ron.

Operator

Your next question comes from the line of Eli Kantor from IFS Securities. Your line is open.

Eli Kantor -- IFS Securities -- Analyst

Good morning, Tony and David.

Tony C. Maranto -- Chairman and Chief Executive Officer

Good morning, Eli.

Eli Kantor -- IFS Securities -- Analyst

As we think about the long-term outlook, can you talk about what level of production growth and free cash flow yield you'd hope to generate in that well field (ph) development stage with oil price underpins that outlook, how do you think about prioritizing the various potential uses of free cash?

Tony C. Maranto -- Chairman and Chief Executive Officer

Right now, Eli, we look at it in terms of steps. One is getting to the position where we are free cash flow positive. I mean, that's first. I mean that's what we're gearing this whole program to do. That's the equation that we try to solve for, putting together the 2019 plan. And at that point, right now we just like to see options. Once we get to the point where we're generating free cash flow, at any point in time, we want optionality in what is the best use of that capital. So, we tend to think in terms of, say, 2020 and beyond, well, starting with 2019, getting free cash flow positive by the end the year, that's step one, and then look toward 2020 and 2021 as being what can we grow production and stay within cash flow. And then, third, free cash flow that we generate, what is the best uses of that cash at that time. Did that answer your question?

Eli Kantor -- IFS Securities -- Analyst

Yeah. As you think about 2020 and 2021, is there any color on that as far as production growth and free cash flow yield that you can kind of give us what you expect to be able to generate $60 oil or other (ph) for whatever long-term price that you're using?

Tony C. Maranto -- Chairman and Chief Executive Officer

What we've done to this point, Eli -- and I'll answer part of the question. What we've done to this point is determine that in 2020, in a $55 world, which is where we're running our strip is that we can grow -- will grow production double-digits within cash flow. And that's probably extent of which we've looked at it to this point.

Eli Kantor -- IFS Securities -- Analyst

Okay. And then, as far as the 2019 budget goes, can you give us a split on what is going toward D&C versus non-D&C spend? What's driving the higher non-D&C spend in the first quarter and how you expect non-D&C spend to trend as a percentage of the overall CapEx longer-term?

David M. Edwards -- Chief Financial Officer

Sure. Eli, on the capital budget, we put out about 15% of that is to be dedicated in non-D&C activity, which is going to be your standard buckets of capitalized G&A, capitalized interest, some leasehold expense. Like you pointed out, the majority of the non-D&C capital is going to be incurred in the first half of the year, largely actually in the first quarter. And the reason for that is, just as we finished up our lease program, which was largely around increasing working interest in units we want to operate and whatnot. Some of that rolled into the first quarter. We expect that activity to slow considerably as we progress through the year.

Eli Kantor -- IFS Securities -- Analyst

Is that 15% number a good use -- a good figure to think about longer-term?

David M. Edwards -- Chief Financial Officer

I'd say so, yeah.

Tony C. Maranto -- Chairman and Chief Executive Officer

I agree.

Eli Kantor -- IFS Securities -- Analyst

All right. Thanks, guys.

Tony C. Maranto -- Chairman and Chief Executive Officer

Thank you, Eli.

Operator

There are no further questions. At this time, I turn the call back over to Tony Maranto.

Tony C. Maranto -- Chairman and Chief Executive Officer

Thank you very much. And thanks to everyone who participated on the call with us. Again, we are really looking forward to 2019, and I guess, we'll talk again on our first quarter call here coming up in a couple of months. Thank you guys very much.

Operator

This concludes today's conference call. You may now disconnect.

Duration: 37 minutes

Call participants:

Alyson Gilbert -- Head, Investor Relations

Tony C. Maranto -- Chairman and Chief Executive Officer

David M. Edwards -- Chief Financial Officer

Derrick Whitfield -- Stifel Financial -- Analyst

Ronald E. Mills -- Johnson Rice -- Analyst

Eli Kantor -- IFS Securities -- Analyst

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