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Chaparral Energy, Inc. (NYSE:CHAP)
Q4 2018 Earnings Conference Call
March 14, 2019, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good morning. My name is Jason, and I will be your conference operator today. At this time, I would like to welcome everyone to the Chaparral Energy Year End 2018 Financial and Operational Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press *1 on your telephone keypad. If you would like to withdraw your question, press #. Thank you. Patrick Graham, Senior Director of Corporate Finance, you may begin your conference.

Patrick Graham -- Senior Director, Corporate Finance

Thank you, operator. Good morning, everyone, and welcome to Chaparral Energy's Fourth Quarter and Full Year 2018 Conference Call. Participating on the call today are Chaparral's Chief Executive Officer Earl Reynolds and Chief Financial Officer Joe Evans. Before we begin, I'd like to encourage you to download our 10-K and corresponding earnings release as well as our updated company presentation, which were filed this morning and are currently available on the Investors section of our website. You can also sign up to automatically receive updates about Chaparral through the RSS feed on our Investors page.

Please be aware that during the call, we will discuss certain topics that contain forward-looking statements based on our beliefs, assumptions, and information currently available to our management team. Although we believe expectations reflected in such forward-looking statements are reasonable, we can give no assurance that they will prove to be correct. There are numerous factors which could cause actual results to differ materially from what is discussed. You can read our full disclosure on forward-looking statements and risk factors associated with our business in our most recent 10-K. In addition, we will also present certain non-GAAP measures, a reconciliation to which can be found in our 10-K. With that said, I will now turn the call over to Earl.

K Earl Reynolds -- Chief Executive Officer

Thank you, Patrick, and good morning, everyone, and thank you for joining us today. I am very pleased to report that Chaparral continued to achieve strong operational and financial results during the fourth quarter, but before I go into detail about our results, I would like to take a few minutes to discuss the truly historic year Chaparral had.

Throughout 2018, we strategically added to our premier STACK acreage position, uplisted to the New York Stock Exchange, successfully completed a $300 million senior notes offering, and increased our borrowing base to $325 million. Operationally, we grew our STACK production and reserves by 50% on a year-over-year basis while significantly driving down operating cost and generating $125 million of adjusted EBITDA for the year. As a result, we have continued to build a solid foundation for success and increased the value of our assets while strengthening our balance sheet and expanding our financial flexibility.

Total company production grew 13% year over year on a pro forma basis for our divested EOR assets to 20,500 BOE per day during 2018, while STACK production increased 52% during the same period to 14,500 BOE per day. Both were at the midpoint of our previously issued guidance. As you may remember, we increased our production guidance during our last conference call.

For the fourth quarter, total company production was 21,700 BOE per day and STACK production was 16,600 BOE per day. Overall, total company production mix for the year was 36% oil, 25% NGLs, and 39% natural gas. Our production performance has been driven by excellent results we have realized from our STACK and Merge capital program, along with lower PDP decline from our proactive artificial lift optimization efforts.

For full year 2019, we expect total company production to be between 25,000-27,000 BOE per day, which marks a 22-32% year-over-year growth rate. Total STACK production is expected to increase to 21,000-23,000 BOE per day, or an estimated 45-59% growth on a year-over-year basis. For the first quarter of 2019, I'd like to point out that production will be impacted by the timing of first sales associated with our spacing test and remaining joint venture wells we plan to bring online. As mentioned in our guidance release, only about 10% of our operated net wells are estimated to record first sales during the first quarter. All 11 wells of our Canadian County Merge Foraker spacing test are slated to come online during the second quarter. With this in mind, we expect first-quarter total production to be at or slightly below the previous quarter, with a significant ramp-up in the second quarter and beyond.

Along with our tremendous production growth, we also realized a 35% year-over-year increase adjusted for divestitures and our year-end SEC 2018 proved reserves to 94.8 million BOE. In addition, the PV10 value of our reserves also grew considerably to approximately $686 million, which is a 38% increase on a year-over-year basis. Now, 59% of our reserves were classified as proved developed, with 34% oil, 27% NGLs, and 39% natural gas. The estimated PV10 value of our proved reserves as of February 28 strip pricing is approximately $502 million.

For our STACK assets, year-end 2018 reserves increased 50% compared to 2017 from 49.4 million BOE to 74.1 million BOE. The PV10 value of our STACK assets increased to $516 million, or 66% compared to 2017. In the STACK, we replaced 519% of 2018's STACK production with the drill bit finding and development cost of $7.80 per BOE. As a reminder, our 2018 year-end reserve estimates were prepared by a third-party reserve consultant, Cawley Gillespie & Associates.

Now, one of our key goals in '18 was to de-risk much of our Garfield County and Canadian County Merge assets and begin conducting spacing tests across our acreage. In the fourth quarter, we added a fourth operated drilling rig to expand our ability to conduct these spacing tests. During the fourth quarter, we brought 13 gross new operated STACK wells online, two of which were part of our joint venture drilling program. For full year '18, we brought online 48 gross operated STACK wells, of which 18 were in Canadian County, 10 in Kingfisher County, and 20 in Garfield County. This included 19 joint venture wells.

In the fourth quarter of 2018, we began drilling our first full Meramec section spacing test in our Canadian County Merge position. The 11-well Foraker test includes a full-section nine-well Meramec test and a partial-section two-well Woodford test. Drilling of the Foraker test has finished and completion activities are currently under way, with all 11 wells slated to be online in the second quarter.

As a reminder, our first partial spacing test in Canadian County, the Denali, came online in the third quarter of '18, and the results were well above our type curve expectations. Our decision to move forward with the Foraker full-section Meramec test was in large part due to the success of this test. Of the 13 new gross operating wells brought online in the fourth quarter, there were several notable Canadian County Merge wells. The Fairweather 1207 and the Alverstone 1206, both joint venture wells, recorded average three-phase 30-day initial production rates of 1,435 BOE per day and 1,357 BOE per day, of which 31% and 45% was oil. Additionally, the two-well Andes pad recorded an average three-phase 30-day IP rate of 1,048 BOE per day, of which 55% was oil.

During the fourth quarter of '18, we brought online our first operated partial spacing test in Kingfisher County. The five-well King Koopa test included three Meramec and two Osage wells, and was drilled in a section with an original Meramec parent well. We did not see any hydraulic communication between the infield wells, which was a good sign that our frack was contained to near-well bore, as per our design.

Another sign of the frack design effectiveness is the fact that the parent well has successfully returned to its pre-infield production rate. Both of these aspects give us confidence that our frack design will be effective as we move to full-section development. However, our nearest child well to the parent did see lower frack efficiency due to parent/child influence during the frack job, which negatively impacted the initial flow rate of that well. Separately, we experienced a casing issue on one of our three Meramec wells, which resulted in a constrained flow rate and an inconclusive test on that well.

The two unconstrained Meramec wells recorded an average three-phase 30-day IP rate of 484 BOE per day, of which 36% was oil and 30% was NGLs. This was below our expectations due to the lower rate of the nearest child well. The two Osage wells recorded an average three-phase 30-day IP rate of 661 BOE per day, of which 45% was oil and 27% was NGLs, and this result exceeded our expectations.

Overall, when we look at our unconstrained well results, we consider our first Kingfisher spacing test successful and believe our frack design will prove to be effective for full-section development. We also learned a tremendous amount about spacing and parent/child influence. As we've discussed in the past, we approach any technical challenge with a systematic, continuous learning mentality, and we view development spacing design as a good example of this approach. You will see us apply these learnings to subsequent spacing tests throughout 2019.

As of year end 2018, we have brought online a total of 22 joint venture wells and expect to finish our 30-well joint venture program early this year. Based on the results of our joint venture and our drilling program, we believe we have effectively de-risked more than 50% of our Garfield County acreage and more than 80% of our Canadian County Merge position.

In 2018, we recorded first sales from 44 Meramec and Osage wells, which, on average, have outperformed our expectations. On average, these wells recorded a three-phase 30-day IP rate of 750 BOE per day, of which 47% was oil and 26% was NGLs. And, to further build on our successful operation results, we continue to acquire acreage in and around our core Garfield, Kingfisher, and Canadian County positions throughout '18.

In addition to our 7,000 net acre bolt-on Kingfisher County acquisition, which was completed in the first quarter of 2018, we acquired additional acreage in the STACK, primarily through additional leasing, pooling, and non-cash acreage trades. These non-cash acreage trades increased our recorded capital expenditures by $11 million, which allowed us to increase our footprint in our core development areas. In total for 2018, we added an incremental 24,600 net acres to our existing STACK and Merge position, and ultimately ended the year with approximately 131,000 net acres in the STACK and Merge.

In 2018, we successfully divested a portion of our non-core assets and realized approximately $51 million in sale proceeds. At the time of sale, these properties collectively accounted for approximately 1,900 BOE per day of production. Now, these non-core asset sales have had a positive impact on decreasing our total company LOE, as they had a much higher expense per BOE compared to our STACK assets. Additionally, these sales were the primary driver of the $13 million reduction of our asset retirement obligations in 2018 as compared to '17. Now, you can expect us to continue to rationalize our portfolio where it makes sense, and for 2019, you should anticipate non-core asset sales to be less than '18, and in the range of $5-10 million.

While we continue to monitor market conditions and plan to be flexible with our capital expenditures, our current plan for 2019 is to invest between $275-300 million in capital, of which $228-248 million is dedicated to the STACK and Merge D&C activities. We plan to drill and complete approximately 60-70 gross operated STACK wells during the year, including our eight remaining joint venture program wells. At this time, we intend to allocate approximately 60% of operated D&C capital in our Canadian County Merge assets, 20% in Kingfisher County, and 20% in Garfield County.

Now, we entered the year with four rigs, and plan to decrease our rig count to three rigs during the second quarter once we work through our current spacing test projects. This strategic reduction will allow us to lower our capital budget while still competitively growing production. From a drilling and completion standpoint, we have more than 50% of our 2019 cost structure locked in, and are confident we will be able to lower our average well cost through proactive procurement measures and increased efficiencies. Now, to that end, we are beginning to see aspects of deflation in the service sector as overall basin activity has declined from 2018. You can rest assured we will pursue this extensively as we continue to deliver good well results at the lowest cost.

Lastly, before I turn the call over to Joe, I want to take a moment to thank him for his dedication, commitment, and immeasurable contributions he has made to Chaparral over the past 14 years. Joe has been an integral part of Chaparral's leadership team since joining the company as our Chief Financial Officer in 2005. He has helped us to grow into the company we are today and has mentored and built an outstanding financial staff, and on behalf of the board and all the staff, we thank you for your tremendous service and wish you well in the future. With that, I'll turn the call over to him for him to discuss our 2018 financial results. Joe?

Joseph O. Evans -- Chief Financial Officer and Executive Vice President

Thank you, Earl, and I appreciate those kind words. And, good morning, everyone. As Earl mentioned, our operational execution and impressive STACK growth translated to another strong financial quarter. Chaparral reported net income of $79 million or $1.73 per diluted share for the fourth quarter. For the full year of 2018, we reported net income of $33.4 million or $0.73 per diluted share. Both the fourth-quarter and full-year earnings were impacted by a $94 million and $38 million non-cash change in the fair value of our hedging derivative instruments.

Our adjusted EBITDA for the quarter was $34.4 million, which was virtually flat compared to the third quarter. Full-year 2018 adjusted EBITDA was $125 million, which is down compared to the previous year, primarily due to the sale of our EOR assets in late 2017 as well as the other non-core asset sales.

Revenues for the fourth quarter before the effects of transportation and processing deductions and hedging activities were $65.1 million. For the full year, we recorded $258.8 million in revenue, with $171.7 million and $45.6 million coming from oil and NGLs. Despite increased production, revenues decreased 7% in the fourth quarter as compared to the previous quarter due to a lowering of overall commodity prices.

Crude oil realizations and NGL realizations were down quarter over quarter to $58.06 and $22.84 per barrel. This was slightly offset by improved natural gas realization in the fourth quarter of $2.95 per MCF. For the full year of 2018, our realized crude oil prices increased 31% year over year to $63.99 per barrel, and our realized NGL price of $24.24 per barrel was up 7% year over year. Our realized natural gas price was down 11% year over year to $2.37 per MCF in 2018. This was primarily a result of an increase in our basis differential compared with 2017.

As we've mentioned previously, because of our proximity to Cushing and ample trucking and pipeline capacity, we are not experiencing any of the large WTI differentials similar to other basins. We continue to realize very strong STACK oil net backs, which, for 2018, were less than $1.00 per barrel compared to the average NYMEX settlement.

Looking at our operating costs for the quarter, LOE continued to decrease on a total-company basis as a greater percentage of our production was associated with our lower-cost STACK assets. Our STACK LOE per BOE for the fourth quarter was up slightly to $4.64, and also increased on a full-year basis from $4.31 in 2017 to $4.86 in 2018.

This year-over-year increase was primarily driven by increased costs associated with produced water disposal. We sold a portion of our saltwater disposal system in mid-2018 and have entered into long-term produced water handling arrangements for our core STACK acreage to address these rising costs. As a result of these agreements and our projected increase in production, we expect our STACK LOE per BOE to decrease in 2019, as evidenced by our 2019 guidance. Our total LOE per BOE is expected to be between $5.00-5.50 in 2019, with our STACK LOE per BOE in the range of $3.75-4.25.

For the fourth quarter, our net G&A expense was $10.1 million or $5.05 per BOE and $38.8 million or $5.18 per BOE for the full year '18. This was essentially flat on a quarter-over-quarter per-BOE basis. When adjusted for our non-cash compensation, our net G&A expense per BOE during the fourth quarter was $3.91, and for the full year was $3.73. For the full year of 2019, we expect our net cash G&A expense per BOE to decrease and to be between $2.85-3.35 per BOE.

Now, in total for full year 2018, we invested $341 million in our oil and gas capex. Of that, we invested $194.7 million on our STACK D&C activity, $111.4 million in acquisitions, $11.1 million in capital workovers, and $23.9 million in other costs, which were primarily capitalized G&A and capitalized interest. Of the $194.7 million of the STACK D&C, $38 million was non-operated, $13.2 million was joint venture capex, primarily driven by some inflation, with another $17.2 million associated with additional working interests acquired in several joint venture wells. Of the operated STACK D&C, $92.1 million of the capital was associated with 24 gross operated wells, which were both drilled and completed in 2018, with an average working interest of 83%. In total, for 2018, we drilled or participated in 165 gross or 37 net horizontal STACK wells.

Of the $111.4 million in acquisition capital for 2018, $10.9 million was associated with non-cash acreage trades, as where possible, we look to trade acreage to block up our operated positions in certain sections. Also included in the acreage acquisitions was $54.8 million of costs associated with our 7,000-acre bolt-on acquisition in Kingfisher County in early 2018, as well as an additional $7.7 million in some 3D seismic acquisitions.

In 2019, we expect our operated D&C capital to be in the range of $210-225 million. We anticipate our non-operated capital will be between $17.5-22.5 million, with our acquisition capital to be between $12.5-17.5 million. Total company expenditures for 2019 are expected to be between $275-300 million, which is a reduction from our 2018 capital spend of $341 million.

Relating to hedges, since finalizing our 2018 fall borrowing base redetermination, we have been continuing to layer in additional hedges to protect our cash flow and capital program. A detailed summary of our total hedge positions can be found in this morning's 10-K filing and our March investor presentation, both of which are available on our website.

Commodity derivative contracts for the quarter decreased our average realized oil price from $58.06 to $57.48 per barrel. Including the impact of derivatives, our average realized gas price decreased from $2.95 to $2.50 per MCF, and our average realized NGL price increased from $22.84 to $24.50 per BOE for the quarter.

For the full year of 2018, our average realized oil price decreased from $63.99 to $57.92 after taking into account the impact of derivatives. For 2018, our average realized gas price decreased from $2.37 to $2.21 per MCF and our average realized NGL price increased from $24.24 to $24.47 per BOE after taking into account the impact of those derivatives.

As of December 31st, 2018, we had approximately $37.4 million in cash and cash equivalents and had no borrowings under our $325 million borrowing base. As we previously reported, our borrowing base was increased from $265 million to $325 million during our regularly scheduled fall redetermination process, driven by the value of our premier high-return STACK and Merge assets. As of March 8th, 2018, we had approximately $29 million in cash and cash equivalents and $30 million of borrowings on our credit facility. We did have a non-cash ceiling test impairment of $20.1 million associated with our non-core lease holds outside of the STACK in 2018. These properties had no production, and we do not plan to develop any of this acreage.

Overall, our balance sheet remains strong, with no significant debt maturities until 2022. We will continue to execute on our STACK- and Merge-focused low-cost strategy as we build on our recent successes. With a strong growth profile and disciplined cost control efforts, we are well positioned to profitably grow and unlock the vast potential of our highly economic assets as we strive to deliver value to our shareholders now and into the future.

I'm very proud of the accomplishments that we've had during my 14 years at Chaparral and would like to thank everyone I've worked with for making this such a memorable chapter in my career. And with that, operator, we'll open the call for questions.

Questions and Answers:

Operator

At this time, I would like to remind everyone in order to ask a question, simply press *1 on your telephone keypad. Your first question comes from the line of Derrick Whitfield from Stifel. Your line is open.

Derrick Whitfield -- Stifel Financial -- Managing Director

Good morning, all.

K Earl Reynolds -- Chief Executive Officer

Good morning, Derrick.

Derrick Whitfield -- Stifel Financial -- Managing Director

Regarding the King Koopa pilot, thanks for the detailed comments on well performance. Looking beyond the well results themselves, could you speak to your learnings from the pilot and how you have adjusted spacing and/or well design for the Jester pilot?

K Earl Reynolds -- Chief Executive Officer

Derrick, thanks for that question. I'm happy to do that. From our perspective, it was a key step for us. If you remember, it was a five-well test. We had three in the Meramec and two in the Lower Osage. Our goals going into it were really to see if we could establish if our frack design was going to stay near well bore, because that's what you try to accomplish when you move from what I would call a de-risking phase or delineation phase in, say, drilling the first well in a section to when you start drilling infield wells. And so, we clearly accomplished that. Our frack design is really set up to be able to create near-well-bore complexity. It's different than when we drill our first well in the section and we're basically drilling just to assess the commerciality of the wells. So, we accomplished that, and that gave us a lot of confidence with our frack design going forward, so you'll see a similar design, we'll modify it slightly a little bit with what we learned in the Jesters and beyond.

And then, the next thing really was this question of parent/child, and we did see some communication, as I mentioned, between our frack efficiency of our well closest to the parent. And so, what that told us was about how we had to alter our targeting and, potentially, our frack design as well with subsequent wells. So, the combination of those two things was how we thought about it, and as far as total, we looked at that result as well as what we've done with our Denali test down in Canadian County as well as other companies' spacing tests. We've seen companies really over-drill sections and materially over-capitalize it, and so, we've seen that not work. We feel like where we are right now is six to eight wells, three to four per bench, and we have at least two benches on all of our acreage. So, that's kind of where our head is right now, Derrick.

What I'm going to tell you is this process is a continuing learning thing, and that's one of the things we pride ourselves on at Chaparral. We don't want to get ahead of our skis. We really focus on learning from every one of our investments and trying to incorporate those learnings into subsequent investments such that we can be more efficient, and that's our primary goal. And so, I think you'll see us apply those learnings in our Jester program, and we'll learn from Jester and apply those to the next one, but that's kind of where our head is right now out of six to eight, and I think that's probably in the order of magnitude of what most companies are seeing in the basin proximal to our acreage that have similar geologies. That's how we're thinking about it, and hopefully that gave you more color.

Derrick Whitfield -- Stifel Financial -- Managing Director

That's great. Very helpful, guys. As my follow-up, I want to first congratulate you guys on a capital-disciplined 2019 outlook. As we look beyond 2019, how do you think about balancing your scale and free-cash neutrality objectives assuming a relatively static commodity price environment?

K Earl Reynolds -- Chief Executive Officer

Derrick, it's a great question. I would tell you that just to be crystal clear, our goals are very -- we're very open with our perspective here. We want to be a cash-flow-neutral business. At our size and scale, it makes a challenge, as you can appreciate, with a little over 20,000 BOE a day and our EBITDA last year of $125 million, to be cash-flow neutral and still grow the company into what I would call a sizable scale, especially with our inventory. But, as we think about the future, we're going to be very flexible. Our capital program is really designed to have limited long-term commitments. That's why we were able to easily flex down to three rigs in 2019 as we saw the commodity get very volatile.

You'll see us have that same approach -- very limited, if any, long-term commitments and the ability to flex our program up and down accordingly. But, our primary goal, just to be crystal clear, is to take this company to a cash-flow-neutral position. We believe we can do that with our assets, our execution has been solid, we believe that's -- as we stated in the past, it's an 18-24-month window before we get there, but that's really our primary objective, and remember, we will be flexible accordingly depending upon commodity prices. Right now, our plans are to run three rigs from Q2 through the end of the year. If something were to change and we saw something we didn't like for whatever reason in the commodity, we could flex that down if need be.

Derrick Whitfield -- Stifel Financial -- Managing Director

Great update. Thanks for your time, guys.

K Earl Reynolds -- Chief Executive Officer

Thanks, Derrick.

Operator

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

Ronald Mills -- Johnson Rice -- Analyst

Good morning. Just to follow up on Derrick's first question, in terms of the communication you saw on the child wells, was that communication between just the child wells? It didn't sound like, given that the parent well returned back to its prior levels, there was any impact on that. Just curious if you could explain from a technical standpoint what you think happened and how the change in lateral targeting -- what potential frack design changes, given that you seem pleased with the near-well-bore concentration of your frack.

K Earl Reynolds -- Chief Executive Officer

Ron, it probably warrants a face-to-face to give you much more color on our technical view, but I'll do the best I can over the phone. The thing we saw was -- you said it well -- our parent came back up to its pre-drill rates, and that's a key thing. You've seen these with these parent/child issues in the past with other companies, and the parent just gets completely...basically, it impacts their production materially or their decline materially. We just hadn't seen that. So, what that told us out of our diagnostic work we did post-frack and the frack as we were fracking the well was that our frack stayed near well bore across all of our infield wells, and I will tell you that's another key piece. All of our five wells -- I like to say it this way, it's simple for me to say it -- they really didn't talk to each other very much. In other words, they're not communicating, and that's what you want to see there. So, we saw that with our frack design.

When we were fracking, though, the child well that was nearest the parent -- that particular well -- we obviously had some communication with our frack fluids with that well, and as a result, when we did our diagnostic work post-frack, that particular well had the poorest frack efficiency of all, and as a result, its initial rates were lower than we had expected. We didn't see that in the other wells, so that told us the confidence -- that really was impacted from the parent/child.

So, what are we doing post and what are we learning from that? So, what we've done -- we can alter our landing zone a little bit, we think, on the subsequent wells to try to address direct communication. That's one thing. The second thing we can do is alter our frack design somewhat to try to maybe not get quite as far of a half-link and maybe more of a height growth. Those are things we would possibly do -- we will do. And then, obviously, we'll continue to just look at that option of how far away we can be from our parent, but the combination of those things, Ron, is how we think about the next phase. We're incorporating those learnings into Jester, and you'll see us apply those in other tests as we go forward.

Ronald Mills -- Johnson Rice -- Analyst

Okay, great. And then, as it relates to the well performance versus type curve, particularly on the Osage with a little bit more production history, it seems like that outperformance has grown a little bit relative to your prior presentations. Are you still seeing continued improvements on both the Meramec and Osage relative to type curve, or is that just a longer dataset of some of the later wells that are performing better?

K Earl Reynolds -- Chief Executive Officer

I think it's probably a function of a larger dataset. I don't know that I would say we materially continue to outperform. We've been pretty good -- I think our presentation this morning frames a fairly lengthy dataset of wells as well as time of how we perform versus our type curve. And so, I would say I've got quite a bit of confidence with those type curves today.

The one exception would be the Merge MISS. That's clearly outperformed our type curve expectations, and we're looking really hard at whether we should do something with that particular type curve. But, what I really want to do there is get the Foraker full-section development online and get more data on the full-section development because those parent wells clearly have done very well, materially exceeded our expectations, and had great return. But overall, I don't know that I would say as a broad statement that we continue to creep up in type curve results. We've seen good, consistent results, and that's really what you want.

Our capital program or capital executions have been solid as well, and we expect that to continue in 2019. I mentioned a little bit in my words about deflation and our costs coming down. The guys are executing really well. We're seeing that in our Foraker spacing tests, our operations team is executing, and our wells have actually been drilled faster than we planned, and our fracture went off really well. So, that should manifest itself in lower costs, as well as service section deflation is happening as well, so a combination of all those things. I think what you'll see the step change happen in '19 is relative to our overall economics associated with cost.

Ronald Mills -- Johnson Rice -- Analyst

And then, last one on the spacing test -- the Foraker you just mentioned -- from a spacing standpoint, schematically, it looks like you're really kind of four to five wells on the lower Meramec. Am I reading the schematic right? Thoughts on that spacing design versus what you talked about in terms of the King Koopa results?

K Earl Reynolds -- Chief Executive Officer

Give or take, the Foraker has actually got a little different mode to it. We saw such good results in our Denali test. All of our diagnostic results and all of the well results post the drilling of those wells -- the things have hung in there and we're not seeing any kind of crazy decline that would concern us. So, we actually have a little bit of a hybrid there on the Foraker. Remember, this is a section with no parent wells, and so, no wells have been drilled in this section. So, we've got half a section -- effectively, four wells, and the other half -- and, I'm talking about Meramec only now; I'll talk about Woodford in a second. So, the Meramec Mississippian section is a separate target than, say, the Woodford. So, in half a section, there's four wells that are effectively -- if you well, eight-wells-per-bench-type approach. The other half are five wells. So, we've actually added another well to the other half of that section, so that's why you get nine wells total.

What I'm saying, though, Ron, is I'm saying right now, six to eight total. We really want to see the results of Foraker before we really go out and say we could drill more down in the Merge, so six to eight wells total is our current thinking. Let's get that well result, let's get the Foraker, plenty of history behind us. We've got several more to do on 2019, but that's kind of how you think about it in the Mississippian or the Meramec. And, when you add the Woodford, we're really early in our stage there. If you remember last year, we had some wells early in the year that didn't work very well for us in the Woodford, so we think we've come back. We feel real good about our targeting now, we feel good about our frack design, and so, these are the first two wells we've tested post that learning, so the jury is out for me right now on what the ultimate spacing test will be on the Woodford, but when I talk about it, I'm mainly talking about the Meramec and the Osage in the Mississippian section.

Ronald Mills -- Johnson Rice -- Analyst

Okay, great. Thanks very much, and Joe, best wishes in the future.

Joseph O. Evans -- Chief Financial Officer and Executive Vice President

Thanks, Ron.

K Earl Reynolds -- Chief Executive Officer

Thanks, Ron. I appreciate it.

Operator

Once again, if you would like to ask a question, please press *1 on your telephone keypad. Your next question comes from the line of Jason Wangler from Imperial Capital. Your line is open.

Jason Wangler -- Imperial Capital -- Managing Director

Hey, good morning, guys.

K Earl Reynolds -- Chief Executive Officer

Hey, Jason.

Jason Wangler -- Imperial Capital -- Managing Director

I wanted to ask a little on the -- you talk in the release about the de-risking in Garfield and Canadian. Obviously, you're starting to do quite a bit of the spacing tests and things and more development aspects, but how do you see some of the program set up this year for de-risking the rest of that or where your head is at in terms of that?

K Earl Reynolds -- Chief Executive Officer

Great question. We acquired last year -- sorry, are you speaking in terms of Garfield?

Jason Wangler -- Imperial Capital -- Managing Director

Yeah, Garfield and Canadian is what I was thinking about specifically.

K Earl Reynolds -- Chief Executive Officer

So, let's take Canadian first. Really, 80% -- or, call it 20% un-risk, if you will -- would be principally the Woodford. You can think of it in those terms. So, I think the first step with drilling our two Woodford wells and the Foraker test -- and then, you'll see us drill a few more Woodfords in 2019 -- will give us a lot of good comfort about where we move that de-risking phase. I fully expect that to increase over the year in terms of above the 80% level with our work on the Woodford. When I go to Garfield, about half of it de-risks in 2018. You'll see less capital in Garfield this year, not because we don't like the results, but because we really like what we're seeing in the Merge MISS, and we want to accelerate our understanding on spacing in that context, and we've got some well sections that really don't have parents in them as well down there.

But, as far as Garfield, we shot our 3D on the whole acreage of the block last year. We're in the interpretation phase of that. We're using that 3D to delineate and de-risk it. So, you'll see a few more wells drilled in Garfield this year based on that 3D and to help us de-risk it, and I expect that number to go up in 2019. I can't really quantify how much, but it's a function of how much capital we put there. Right now, we're suggesting around 20% of our capital program to be in Garfield this year, and that's going to be on the heels of our 3D seismic interpretation and incorporating that into our program.

Jason Wangler -- Imperial Capital -- Managing Director

Okay, that's helpful. And then, just -- obviously, you still have a couple positions outside the STACK, and you guys have talked about divestitures in the past and becoming more pure play, if you will. Just where your thoughts are as far as those positions -- obviously, you have the $5-10 million divestiture plan, so to speak, but just what you think about maybe some larger divestitures as the year goes on, or even further in the future.

K Earl Reynolds -- Chief Executive Officer

Jason, I would tell you -- and, I've been real open with my shareholders and investors alike -- that our focus is STACK and Merge, and that's where we want to be. The rest of our asset base is non-core. It provides a real -- we've focused our business down on areas that have a higher margin. That's what's remaining. We do have some other areas we'll be moving out of -- that's where you get the $5-10 million number -- it's really higher-cost, non-core assets. So, the question is would we sell the rest, can we sell the rest, or will we sell the rest? The short answer is yes, yes, yes, but the problem right now is the market for PDP in general is not that strong. I think everybody could testify to that.

And so, really, it's just a balancing act for us of our borrowing base impact and our collateral value for a borrowing base for these non-core assets versus selling them on the open market. You'll see us continue to assess the market interest and appetite for those assets over the course of this year and next, and to the extent we see some bids that make sense to us, you'll see us execute on those, but right now, we've just assumed a fairly conservative divestiture assumption in 2019 of these $5-10 million. You'll see that happen for sure, and those are just areas where we can clean up the portfolio, maybe help the operations be more efficient -- all those things.

Jason Wangler -- Imperial Capital -- Managing Director

Okay. I appreciate the color, thank you.

K Earl Reynolds -- Chief Executive Officer

Thank you for the question.

Operator

Your next question comes from the line of Dustin Tillman from Wells Fargo. Your line is open.

Dustin Tillman -- Wells Fargo -- Analyst

Hey, guys. Thanks for taking the call. Just a couple questions. It seems like oil cost has continued to come down. I didn't see 2019 oil guidance. What is that going to look like?

K Earl Reynolds -- Chief Executive Officer

I don't know that -- Joe, did we provide it?

Joseph O. Evans -- Chief Financial Officer and Executive Vice President

What we've said is -- and, you're right, it's probably a little bit lower over time, but remember, we were selling the assets -- both the ELR and the asset sales during 2018 were primarily oil, so that's probably what's caused it. If you look at our -- one of the ways I thought about it -- if you look at the oil cut in Q3 and Q4, it's probably going to be consistent with what we would expect to have going forward, which is probably in that 33-34% oil range.

Dustin Tillman -- Wells Fargo -- Analyst

Okay, that's helpful. It seems like STACK oil cuts have come down a little bit. Does that have to do with mix between shelf and Merge? What explains the STACK oil cuts coming down?

Joseph O. Evans -- Chief Financial Officer and Executive Vice President

It probably has just slightly, but I think that's probably more to do with -- we had some really high gas wells that have actually exceeded expectations on the gas side, so I think our oil has been right on our type curves and our gas has actually been slightly above.

K Earl Reynolds -- Chief Executive Officer

The other thing -- just to build on that, we have a pretty active OBO program across our acreage. We've participated with a couple of larger companies in the deeper part of the basin, and those are very gassy wells, and so, we had give or take 15-20% working interest in a well, and even because of our smaller production base, you'll see that impact in OBO. So, the short answer is a combination of what Joe talked about -- we actually sold some assets that were oilier, and as it relates to the STACK, I think you're basically starting to see the numbers that we're getting in terms of our oil cuts. Our Canadian County position tends to be a little more gas, as well as our northeastern Garfield. Great returns, phenomenal returns, just a little more gas. And then, our Kingfisher position is a higher-oil position. That's just what Mother Nature made it for us.

Joseph O. Evans -- Chief Financial Officer and Executive Vice President

And then, remember, we spent most of our capital in 2018 in Garfield and Canadian County, which, at the end of the year, was when we started drilling in Kingfisher.

K Earl Reynolds -- Chief Executive Officer

That's correct, Joe. Good point.

Dustin Tillman -- Wells Fargo -- Analyst

Okay, I appreciate that. You guys talk about the capital discipline -- there's still a pretty healthy outspend in '19. You have bonds that are trading sub-$60.00 right now. How does it make sense to continue to outspend rather than looking to repurchase debt at such a deep discount?

Joseph O. Evans -- Chief Financial Officer and Executive Vice President

Dustin, that's an age-old question. The real answer to start with is there's a window -- I believe it's 12 months -- that we're not able to do any repurchasing under the way our indenture was done, and so, subsequent to that, it becomes an alternative to look at, and I'm sure that Chaparral will continue to look at that, but right now, that's not in the plans as a debt repurchase, but certainly, if the bonds continue to trade where they are, that's something you continue to look at -- is that the right use of your capital?

K Earl Reynolds -- Chief Executive Officer

We look at all those options, including the share repurchase bonds -- we'll evaluate those once we have the ability to do it, but as we thought about our program for '19, as we thought about our asset base, and clearly, our position, our results and execution have been so strong, we felt like it made a lot of sense to bring our value forward as best we can with our capital program, and that's the design of this program, balancing that with capital discipline where appropriate, and specifically, you saw us go from four to three rigs, as an example. As I mentioned in my comments, we will remain flexible accordingly depending upon any kind of change in the commodity relative to that.

Our view is that our execution has been strong, we've seen good results, we're delivering great returns that we should outspend this year for 2019, and that was the design of our program. Our bond deal last year, as you mentioned, allowed us to get the liquidities in a great place -- no concerns about that -- and so, I think a combination of flexibility and results drive those decisions, but ultimately, our vision and our goal is to be cash-flow neutral, as I mentioned in the earlier questions on this call. So, that's truly our goal, but in terms of whether we would allocate capital to buy back our debt -- clearly, it's an option, and myself and our board will look at those options when we have the ability at that time.

Dustin Tillman -- Wells Fargo -- Analyst

Okay. As a credit guy looking at it, with all of your peers in the area under significant distress, having a clean balance sheet provides optionality that drilling through the inventory may not provide today. One last question, if it's OK. You talked about six to eight wells a section based on the two zones. Is that what's implied in the reserve report? What does the reserve report use as spacing assumptions?

K Earl Reynolds -- Chief Executive Officer

Reserve reports can be proved only, so now you're talking about... Basically, our auditor is pretty conservative, so we may only get two wells offset each one of our PDP wells, and so, you may only have two wells in that particular section. It just depends. It's very much individual to actual PDP wells. But, we really don't have -- we're not booked that way from a proved reserve perspective. That number I'm quoting would be more of a 3P kappa number.

Dustin Tillman -- Wells Fargo -- Analyst

Thanks, guys.

Operator

Once again, if you would like to ask a question, simply press *1 on your telephone keypad. Your next question comes from the line of Korina Markou from Carlyon AG. Your line is open.

Philip Higson -- Carlyon AG -- Founder

Hi, good afternoon, guys. It's actually Philip Higson at Carlyon AG in Zurich. Thank you very much. Interesting call. My question is on the same discussion about the free-cash-flow-neutral. I totally get the trade-off between your different decisions, but just referring back to your call in November, I think you equally had the 24 months as your likely timeline before you could become more cash-flow neutral. When I look at what the market assumes for the overspend, it's about $150 million in 2019 and about $90 million in 2020.

Do you have a different view as you approach either the revolver timeline or you get further out nearer to the bond getting near to 2023? Could you really have cash-flow neutral, or is this something that the 24 months out is more of a regular answer? How determined are you to try and get the share price away from being $5.00? When I'm coming from a completely outside view, I see that the J.P. Morgan revolver was really displacing some of the bondholders, which is why they're trading at $60.00, and both of those groups are displacing the equity holders, which is why it's trading at $5.00. So, somehow or other, the outspend needs to be lower to try and bring back those two groups onside. So, just a bit more color on that -- I know it's a question you've already had twice.

Joseph O. Evans -- Chief Financial Officer and Executive Vice President

The long-term answer is... I'm not 100% sure I understand exactly why our stock trades where it is. I would say that we are a small company. We've been fairly consistent that we think at our size, we are going to need to have an outspend in order to develop the assets and show what we believe the spacing really can be. I believe there are basin issues that cause some of the stock and the bonds to be priced where they are, not specifically Chaparral issues, so we're trying to show what we believe is the potential for our set of assets in the STACK.

So, we're being fairly consistent, and you're right -- if you look at the numbers, you could have an additional outspend in 2020. We believe that as we proceed through that, we will continue to have more than enough liquidity that will justify that outspend, and I think the thought process is if we can really hit the targets that we've got, we're going to show that you can create value, that we can get to cash-flow neutral, and I believe that the stock will recognize that, that we'll differentiate ourselves between other players in the basin, which we have an operational execution that allows us to show a return on our assets, and that just hasn't happened yet in this basin.

K Earl Reynolds -- Chief Executive Officer

Just to build on it, to Joe's point, the performance of the equity -- and now, more recently, the bonds -- it really is a challenge for us to get our head around what's driving that, and clearly, at least in context of our results -- so, our results have met and exceeded expectations across -- ever since we've emerged, and so, it's a simple -- the way we think about it here is if we're getting returns materially above our cost of capital, then we should be reinvesting that capital.

Granted, that requires an outspend, and as you pointed out, we're doing that in 2019. We believe that with a mindful eye of capital discipline ensuring that we don't do anything that's way in front of our understanding and learning of our capital program, which is what we've never done -- we've always stayed in front of ourselves relative to that -- we will be able to get to cash-flow neutral in the period that we've talked about, and we feel confident with that, and that's really our goal. Unfortunately, that requires us to outspend this year, and we've been very clear on that point.

But, as it relates to what's going on around us, it's pretty clear that it's happened -- some other companies have not focused on that and have not had the same execution results, and we're very mindful of that, and we don't expect to have the same sorts of issues with our execution program at all. Candidly, we have a lot of differences between what we're doing and what other companies have done. I'm happy to go through those if you're interest, but it's just -- our view is a little different, and that's how we view our execution. It's been the foundation. We believe over time, the market will understand that and see there's a difference, and as a result, our equity prices and our bond prices should be back to where they should be.

Philip Higson -- Carlyon AG -- Founder

Got it. When you look at the Encana deal when they bought Newfield, both of them were actually moving toward free-cash-flow neutral. Encana -- I know the scale is way different -- that acquisition was possible because they were free-cash-flow neutral. I think the answer to why everything is so depressed -- we've obviously had the drama around your space with the other names, but I do think that people are just uncomfortable with the runway with the free-cash-flow-negative at such a great level.

So, that's just an observation from somebody that doesn't know much about your business, but it would be great to see that runway get closer to, say, a $50 million overspend rather than a $150 million. Everything else being equal, I think that would be enough to get the shares to be moving and to people feeling they're not being squeezed out by the debtholders over time. Anyway, thank you for your answers.

K Earl Reynolds -- Chief Executive Officer

Thank you. I appreciate it.

Operator

There are no more questions at this time. I turn the call back over to Mr. Earl Reynolds for closing remarks.

K Earl Reynolds -- Chief Executive Officer

Okay, thank you. Before my closing remarks, I'd like to once again thank Joe for all he's done to help Chaparral grow over the years. I also want to take this opportunity to introduce Scott Pittman, who, as was recently announced, will assume the role of Chief Financial Officer after Joe's departure tomorrow. Scott has more than 14 years of senior E&P financial management, commercial, and investment banking experience. We believe his background and experience will be very beneficial to Chaparral going forward, and we welcome him to our management team. Scott?

Scott Pittman -- Incoming Chief Financial Officer and Executive Vice President

Thank you, Earl. I'm very excited to be joining the team and look forward to building on the great momentum already here in place at Chaparral Energy.

K Earl Reynolds -- Chief Executive Officer

In closing, as you have heard this morning, we are very excited about our operational progress, the outstanding results we have seen to date, and the solid financial foundation we have built. Our de-risking success in Garfield and Canadian Counties reinforces the value of this underappreciated acreage, where we are achieving excellent economics and capital efficiency. We are excited about Chaparral's future in our differentiated STACK and Merge acreage. We remain confident in our operations team and the strong culture of continuous learning, along with applied science and technology, which sets our drilling and completion execution apart from our competition.

We will continue to conduct additional spacing tests and, where appropriate, full-section development as we move into the next phase of our growth and evolve and optimize development plans for our deep drilling inventory. We are extremely excited about where we are and what we've been able to accomplish thus far, and believe with continued operational and technical excellence, we will further demonstrate Chaparral's tremendous value potential. Scott and I look forward to speaking and meeting with you in the near future and hope to see many of you at our upcoming conferences. Thank you.

Operator

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

Duration: 58 minutes

Call participants:

Patrick Graham -- Senior Director, Corporate Finance

K Earl Reynolds -- Chief Executive Officer

Joseph O. Evans -- Chief Financial Officer and Executive Vice President

Scott Pittman -- Incoming Chief Financial Officer and Executive Vice President

Derrick Whitfield -- Stifel Financial -- Managing Director

Ronald Mills -- Johnson Rice -- Analyst

Jason Wangler -- Imperial Capital -- Managing Director

Dustin Tillman -- Wells Fargo -- Analyst

Philip Higson -- Carlyon AG -- Founder

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