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Chaparral Energy (CHAP)
Q2 2019 Earnings Call
Aug 8, 2019, 10:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good morning. My name is Adam, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Chaparral Energy Q2 2019 Financial and Operational Results Conference Call.
[Operator Instructions]
Patrick Graham, Senior Director of Corporate Finance, you may begin your conference.
Patrick Graham -- Senior Director of Corporate Finance
Thank you, operator. Good morning, everyone, and welcome to Chaparral Energy's
Second Quarter 2019 Conference Call. Participating on the call today are Chaparral's Chief Executive Officer, Earl Reynolds; and Chief Financial Officer, Scott Pittman. Before we begin, I'd like to encourage you to download our 10-Q and corresponding earnings release as well as our updated company presentation, which are currently available in 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 the risk factors associated with our business in our most recent 10-Q. In addition, we will also present certain non-GAAP measures, a reconciliation to which can be found in our 10-Q. With that said, I will now turn the call over to Earl. Earl?
K. Earl Reynolds -- Chief Executive Officer
Thank you, Patrick, and good morning, everyone, and thank you for joining us today. I'm happy to report that we had an outstanding quarter, and we again were able to deliver operational results within or above our guidance ranges, as we've done consistently since becoming a publicly traded company. Both total company and STACK production came in above the high end of our second quarter guidance, driven by exceptional performance from our Foraker spacing test and an overall increase in wells brought online during the quarter.
We grew adjusted EBITDA by 54% quarter-over-quarter to $43,700,000 and an increased total company production by 36% to 28,300 BOE per day. As just as impressive, our STACK production grew 50% over the first quarter to 23,800 BOE per day. Overall, total company production mix for the second quarter was 34% of oil, 29% NGLs and 37% natural gas. In the second quarter, we had 28 wells with first sales, a significant increase over the first quarter, which only had 12 wells with first sales. Of the 28 wells, 14 were in Canadian County, 10 were in Kingfisher County and 4 were in Garfield.
As you may remember, we forecasted an increase in second quarter production during our last conference call, primarily due to the timing of new wells being brought online, which included our 11-well cube style codevelopment Foraker spacing test in Canadian County. As we move exclusively to multi-well, partial and full section spacing developments, the growth trajectory of our STACK and Merge production will continue to be impacted by timing associated with these operating developments in any given quarter. I'd like to now discuss our outstanding drilling and completion results in more detail and give you some updates on our recent spacing test performance.
And you could turn to slide 12 to 14 in our August investor presentation to view some of these details that I'll be discussing this morning. We completed the drilling of our 11-well cube style co-development Foraker spacing test in Canadian County during the first quarter of 2019 and finalized completion of the wells early in the second quarter. The multi-well test was drilled from 3 pads into 3 distinct drilling targets, the upper and Lower Meramec and the Woodford.
There were 4 wells drilled in the Upper Meramec, 5 in the Lower Meramec and 2 in the Woodford. This design was based upon an incorporated extensive learnings from our successful 3-well Denali test that was completed last year. To maximize completion efficiency, the wells were fracture stimulated in a manner, which was designed to create the greatest amount of near well bore complexity, while maintaining sufficient pressure boundaries to minimize inter-well frac communication. The Foraker wells continue to exceed our expectations.
The 9 Meramec wells had an average 30-day IP rate of 1,491 BOE per day and has continued very, very strong production. All 9 Meramec wells are significantly outperforming the company's old expectations and have achieved average 120-day IP rates at 148% of type curve. The 2 Woodford wells have also performed well and had a 30-day IP rates of 754 BOE per day. Woodford wells are meeting the company's oil expectations with an average 120-day IP rates at 101% of type curve. Now one of the most interesting things we saw from the Meramec wells was the enhanced oil rates that were derived from a cube style development, whose frac design has created extensive near well bore complexity.
These enhanced oil rates have materially exceeded our expectations, and our returns are very encouraging. And I'll remind you, that's our primary objective. Overall, after more than four months of production from our Foraker full section development, we remain confident that our technical team's original spacing assessment of 3 to 4 wells per drilling target or 6 to 8 wells per section in the case of 2 targets is optimum. To that end, as an a follow-up to our Foraker success, we have modified our drilling plans in the second half of the year to include another full section development in Canadian County.
In the fourth quarter, we plan to begin drilling a six to eight well Meramec project called the Greenback. It's in very close proximity to the successful Foraker development. In addition to the Foraker, we are seeing overall strong results from additional spacing tests across our acreage. As you think about optimal spacing zone, you have to consider, among other things, parent well communication risk. We have completed tests with as many as 2 existing parents in the section and are developing techniques that effectively manage parent-child communication risk.
We've recently completed several spacing projects in Canadian and Kingfisher County, that have incorporated results from outside operated test as well as our own internal design that is based upon our technical team's selective learnings. These recent tests are encouraging, in that on average, there, we are exceeding our 60-day IP oil type curve expectations by 147% in Canadian County and 122% Kingfisher County. These results provide us with confidence in our spacing design and the parent-child risk management techniques. Now I want to remind you that the tests are geologically driven based upon our subsurface earth model.
And we've had some significant successes and some learnings along the way. But as a whole, these projects are exceeding our expectations. In addition to these tests, we also brought online the first 4 wells of our Kingfisher County Hennessey unit partial spacing test, where we are utilizing our Come & Go concept. The Come & Go concept is the brainchild of our operations team, where we are hoping to achieve the benefits of a cube style full section development with reduced cycle time. As part of this test, we had to shut in these 4 wells prior to them achieving their peak 30-day IP in order to finish drilling and completion operations on the remaining 2 wells.
Now we anticipate being able to discuss our Come & Go project in more detail when we have more information. Looking at the broad array of wells we've drilled in the past 2 years, they have, on average, consistently beat our expectations as we continue to refine our targeting and development design along the way. As we discussed in the past, we have learned a tremendous amount about our acreage, well placement, well spacing, drilling to completion techniques and parent-child influence. We approach every technical challenge with a systematic, continuous learning mentality, and we've applied learnings from each and every well we drill or participate in to ensure that we maximize future well productivity and consistently deliver the returns that we expect. Since we began our operating spacing development programs in 2018, we have brought online 32 operated Meramec and Osage spacing wells, and the average 30-day IP rates of those wells has exceeded our expectations with an average rate of 937 BOE per day, and that includes 50% oil and 75% liquids.
Now we are also very proud of our drilling and depletions teams ability to capture and incorporate operational efficiencies, including increases in drilling footage per day, more efficient frac designs and doubling the number of fracs that can be completed per day. By capturing these efficiencies, we have seen our recent average Osage and Merge MISS well costs declining materially compared to our 2018 average and are currently ranging between $3.5 million to $4 million.
Through the first half of the year, we have been able to reduce our average well cost by approximately 15% to 20% compared to our 2018 for our Merge MISS and Osage drilling program. Now in addition to the cost savings, we're also reducing our cycle comps significantly, which were positively impacting our well level economics. As we discussed in our last call, we entered into the year with 4 rigs and, as expected, transitioned to 3 rigs at the end of the first quarter.
We operated 3 rigs in the second quarter and plan to continue to operate 3 rigs for the remainder of '19, with all of the capital spend in the second half of '19, focused on Canadian and Kingfisher County. We will continue to monitor market conditions, and we have the flexibility to reduce operating activity as only 2 of our full -- our rigs are contracted through the end of the year, with the third being on a well to well basis. Now I'd like to now briefly discuss our updated 2019 guidance.
We continue to proactively take measures to reduce costs across our entire business. As a result of our G&A cost reduction initiatives, we are reducing our G&A per BOE guidance by 11% to $2.50 to $3 per BOE. And as a result of our operational successes, we are lowering our STACK LOE per BOE guidance by 4% to $3.60 to $4.10 per BOE. We're also reaffirming our original full year 2019 production estimates of 25,000 to 27,000 BOE per day, but lowering our capital expenditure guidance by approximately 5% to $260 million to $285 million. For the third quarter of 2019, we expect total company production to be between 26,000 and 27,500 BOE per day and STACK production to be between 21,500 to 23,000 BOE per day.
The decline in production for the second quarter is primarily due to the impact of reducing activity from 4 rigs to 3 beginning in the second quarter and the associated timing of new development wells being placed online, going from 28 wells in the second quarter to an estimated 10 to 15 during third quarter. As we look to the future, achieving cash flow neutrality is an absolute priority for our company. And we stated that we believe we can achieve that toward the second half of '20. We're already in the early stages of our 2020 budgeting process and working through a multitude of scenarios that will provide us the best path to our goal of achieving cash flow neutrality in 2020. Operationally, we have differentiated ourselves from an execution standpoint, and we are proud of this distinction.
Having said that, we believe our -- to remain a top quartile operator, we have to do everything we can to reduce our costs while in this volatile price environment. You can expect us to continue to proactively take measures to reduce costs across all aspects of our spend. We're having a very strong year operationally and have had made material investments in capital, LOE and G&A reductions, which has provided us with confidence to update our full year 2019 guidance with lower cost expectations, while maintaining our original full year production guidance.
We plan to continue to deliver on our guidance as we've consistently done since becoming public. And we'll remain focused on execution to strong returns that will create long-term value for our shareholders. Now with that, I'll turn the call over to Scott to discuss our second quarter financial results. Scott?
Scott Pittman -- Chief Financial Officer
Thank you, Earl, and good morning, everyone. As Earl mentioned, our second quarter operational results were quite impressive and translated to significant growth in adjusted EBITDA. While Chaparral reported a net loss of $45.2 million or $0.99 per share for the second quarter, it was impacted by a $63.6 million noncash ceiling test impairment charge, primarily due to a decrease in prices used to estimate reserves and partially offset by a $17.6 million noncash change in the fair value of our hedging.
Our adjusted EBITDA grew 54% quarter-over-quarter to $43.7 million. This significant increase was driven primarily by higher production and lower per unit operating costs. Revenues for the second quarter were $72.5 million, which included $51 million from oil, $11 million from NGLs and $10.5 million from natural gas. Revenues increased 36% in the second quarter compared to the previous quarter, driven by higher production. Realized pricing overall was nearly flat versus the first quarter, but we saw an increase in crude oil pricing and a decrease in NGLs and natural gas pricing. For the second quarter, excluding derivative sales and settlements, we realized $58.41 per barrel for crude oil, $14.72 per barrel for NGLs and $1.83 for natural gas.
As I mentioned previously, because of our proximity to Cushing and ample trucking and pipeline capacity, we are not experiencing any large WTI differentials similar to other basins. We continue to realize very strong STACK oil netbacks and for the second quarter, they were $1.37 a barrel per compared to NYMEX. We had significant decreases in our operating cost for the quarter, both for total company LOE and STACK LOE were down 21% as compared to the previous quarter. For the second quarter, the total company LOE was $5.19 per BOE, and the STACK LOE was $3.90 per BOE.
The decrease in LOE was primarily driven by increase in volumes and lower saltwater disposal costs. As Earl pointed out, we have lowered our full year 2019 LOE guidance. For STACK LOE, we lowered our guidance 4% to between $3.60 and $4.10 per BOE. For the total company, we lowered guidance to a range of $4.9 and $5.4 per BOE. For the second quarter, our net G&A expense was $7.3 million or $2.84 per BOE. This was a reduction of 36% on a quarter-over-quarter per BOE basis. When adjusting for noncash compensation, our net cash and G&A expense per BOE during the second quarter was $2.52 per BOE.
This is a reduction of 27% compared to the first quarter of 2019. To better align our G&A and overhead expenses with current industry conditions, we completed a workforce reduction in July. Since the beginning of 2019, Chaparral has reduced its corporate workforce by 23% and implemented cost reduction initiatives, that will result in annualized G&A savings of 20% to 25%. The full impact of these reductions will be realized in 2020, with the initial savings flowing through the second half of 2019. We expect to incur a onetime charge of approximately $1 million in the third quarter due to severance costs associated with the reduction.
As Earl pointed out, we have also lowered our full year 2019 guidance for cash G&A expense of 11% to a range of $2.50 to $3 per BOE. Shifting to capex, we invested $75.7 million in the second quarter. Of that, we invested $64.7 million on STACK drilling and completion activity, $3.2 million in acquisitions, $1.8 million on capital workover and $6 million on corporate allocations, consisting of capitalized G&A, capitalized interest and asset retirement obligations. Of the $64.7 million of STACK D&C, $2.1 million was non-operated and $3.5 million was joint venture capex. Our operated drilling rig count declined as expected from 4 rigs to 3 rigs toward the end of the first quarter of 2019. But with a significant increase in completions on wells brought online, our capex spend was almost flat for the quarter.
We are forecasting our capex to decrease in the second half of 2019 as compared to the first half. For full year 2019, we are reducing our capex to a range of $260 million to $285 million, with no impact to our previous full year production expectations. On August 5, we entered into an agreement to sell the building housing our headquarters. Proceeds from the sale of the building will be used to eliminate the related debt by approximately $8.3 million, and we estimate annual savings of approximately $1 million will be achieved.
As of the end of the second quarter, we had approximately $33 million in cash and cash equivalents and $85 million drawn under our $325 million credit facility. Our balance sheet remains strong with no significant maturities until 2022. With a strong growth profile and disciplined cost control efforts, our differentiated STACK and Merge acreage, coupled with our low-cost operations has positioned us to profitably grow and unlock the potential of our economic assets as we strive to deliver value to our shareholders now and into the future.
And with that, I'll turn the call back over to Earl.
K. Earl Reynolds -- Chief Executive Officer
Thank you, Scott. In closing this morning, as you've heard, we are very excited about our operational progress, the outstanding results we are seeing in a solid financial foundation we've built. We believe we have clearly differentiated ourselves as we continue to deliver strong operational results, which has enabled us to consistently meet or beat our guidance. We remain confident in our operations team and a strong culture of learning, science and technology, which has resulted in significant cost savings and flows set our drilling and completion execution apart from our peers.
We continue to see strong overall results from additional spacing tests, and we are planning another full section development in Canadian County later this year. The growth trajectory of Chaparral STACK, Merge production will continue to be impacted by spacing tests, such as the one I just mentioned moving forward, with production dependent on how many wells are completed and brought in line in any given quarter.
This may impact quarterly growth, but we will continue to deliver on guidance because it is very important to us that we continue to do what we say we'll do. I want to assure you that achieving cash flow neutrality is a highest priority for us, and we will begin -- we have begun to work on that with our 2020 budgeting effort. We are very excited about our future and believe that with continued operational and technical excellence, we will further demonstrate Chaparral's tremendous value potential to all of our shareholders.
With that, I'll turn -- open up the call for questions from the group.
Questions and Answers:
Operator
[Operator Instructions] Your first question comes from Derrick Whitfield, Stifel Financial. Your line is open.
Derrick Whitfield -- Stifel Financial -- Analyst
Regarding the 2019 guidance, your implied Q4 guide suggests the production levels similar to Q2 levels. I imagine there's some conservatism built in based on the timing of projects and the maturity of recent pilots. But could you share with us your thoughts on how you expect the production profile to project for the year and early into next year?
K. Earl Reynolds -- Chief Executive Officer
Eric, great question. We knew that was something that would be near and dear to a lot of people's hearts. I mean, basically, no, we like to try to deliver our numbers. Your instincts are right on that one. But there's a couple of things you need to know. We are planning -- I mentioned the Greenback spacing test in Q4. So you think about that in terms of -- that's going to be 6 to 8 wells, and so there will be rig activity and completion activity will be impacted -- associated with that.
But it's really a function of our Q2 results were just phenomenal, right? They really, really were strong. Q1 was lower of course than Q2. So feel pretty good about the back half of the year, but the net wells we're bringing on in Q3 is just materially lower in Q2, and that's really impacting our quarterly guidance. And so we're going to have this, Derrick, with our size, and our capital program, we're going to have this lumpy production.
But the back half of the year, still feel very good about it. You said, what did you say, conservative, but we like to make our numbers, but we do have some things that are impacting the actual production profile. But we will be bringing -- if -- executing our Greenback project will be in Q4, they will be coming online in Q1 of 2020. And so that obviously would have an impact on our growth trajectory as we go into '20.
Derrick Whitfield -- Stifel Financial -- Analyst
Makes sense. And as my follow-up, could you speak to the D&C process you're employing in sections of existing parent wells to minimize parent-child impacts?
K. Earl Reynolds -- Chief Executive Officer
Yes. Great question, again, Derrick. We -- look, I mean, there's lots of techniques you can employ. We tried all of them. The most basic technique is just shutting in your parent for a period time prior to initiating your frac. And we've obviously been doing that. We have moved to individuals. So when you look at every single well, where is the parent drill versus where are we drilling the children well. If it's in a different zone, that might impact how we think about it.
Are there anything from a geologic perspective that could cause us to think that we would not have as much communication or would have more. So all those pieces are an aspect of our planning process. One thing we've done recently with some wells as we go -- is -- we call it a preload, where we actually shut the well and that we actually pump water at a very low volume, a low-pressure into the parent well prior to fracking. So that was another thing we've done.
So a combination of all those techniques, we do to try to manage to make sure -- we haven't gone down a path of some companies have actually gone in and frac the well or refrac the well. We haven't done that yet, but we've done the pre-load, and we've had some good success with that. So all those pieces or aspects, look at the geology, very comprehensive. We're looking at where we drill the parent versus the child. And then using either just to shut in for sure, of course, and then maybe the preload would be one more aspect of it.
Derrick Whitfield -- Stifel Financial -- Analyst
Thanks that's very helpful. Thanks for your time.
K. Earl Reynolds -- Chief Executive Officer
Thank you.
Operator
And your next question comes from Jason Wangler of Imperial Capital. Your line is open.
Jason Andrew Wangler -- Imperial Capital -- Analyst
I wanted to ask, you mentioned in your comments, Earl, about 3 or 4 wells per section, and obviously on the release, you talked to 6 to 8 wells at the Greenback project. Maybe it's kind of what you were saying there with Derrick's question. But how do you kind of determine what you're going to ultimately do with that spacing in that 6 to 8-well program as you move forward with that project later this year?
K. Earl Reynolds -- Chief Executive Officer
Jason, listen, the way we think about this is I always like to tell the team, it's always, always about the geology. And so we've got 3D seismic over all of our acreage, and we've got a comprehensive 3D seismic-derived earth model. And that allows us to really understand the stratigraphy of the rock.
And so the reason I say that is it helps us implicit -- boosts our activity we drill with our derisking phase. We know what rocks we know are commercial. So when I say 3 to 4, I'm talking about per drilling target, OK? So if I'm saying 6 to 8, that implies that we have 2 targets, that we believe are separated and can be produced individually. So in the case of the Greenback, and I'm talking about the Merge MISS or the Meramec section in Canadian County. I'm talking about 2 distinct targets that we're seeing to drill. And we're saying we will put 3 to 4 wells per target.
And so in the case of the Greenback and the Foraker as well, that's how you derive the numbers. But I may go to a different area Derrick Jason, and based upon our technical data and our subsurface understanding, our name and all the information we've achieved, we may only see one target, right?
And so that may be with that particular section in the Meramec, and you'll say, you may only have 3 to 4 wells. So that's how you have to look at it. So it's individually designed based on the geology and our understanding. And so that's how we think about it. So in the Greenback, we're seeing 6 to 8, which is effectively 2 targets.
Jason Andrew Wangler -- Imperial Capital -- Analyst
Okay, that's helpful. And then, Scott, just one quick one for you. I didn't see it in the Q. But could you just give us an update on what the availability is on the credit facility post the second quarter numbers?
Scott Pittman -- Chief Financial Officer
Yes. So if you go into the Q, you'll find it's in our current ratio reconciliation, it's $190 million of availability. So if you'll remember back to where we were in the first quarter, it was $154 million, I believe, of liquidity or availability. And so per consistent message with the growth in production, the execution that we've had, we were actually always planning and intent on actually accruing liquidity as we continue throughout the quarter. And so $190 million is where the availability would be now. And we hope to kind of continue to do that throughout the year.
Jason Andrew Wangler -- Imperial Capital -- Analyst
Great. I appreciate it. Thanks guys.
Operator
Your next question comes from John White of Roth Capital. Your line is open. Your line is open.
John White -- Roth Capital -- Analyst
Congratulations on a strong quarter.
K. Earl Reynolds -- Chief Executive Officer
Thank you.
John White -- Roth Capital -- Analyst
So that preload technique sounds very interesting. I might want to follow-up with you offline on that. But on your frac jobs and completion techniques, in general, has been any significant tweaking or changes over the last quarter? And in particular, are you using local sand to prop inand how's that working out?
K. Earl Reynolds -- Chief Executive Officer
Yes, John. Yes, great question. I don't know if I would say a lot of tweaking from Q1. Q2 is when we really did all of -- fracked all of our Foraker wells. And so -- but generally speaking, yes, short answer is we use all local sand. And one of the big changes from '18 might have been more of a use of primarily 100 mesh sand as compared to 40 70 that maybe we have used them in the past. So that's one big tweek from last year. But as compared to Q1 to Q2, I don't know that I'd say material changes
We've kind of got our head around where we want to be based upon the rock, and it is very much tied with the rock. I might do a little different frac up in Kingfisher County and an Osage rock versus a Meramec or Woodford rock down in the Merge. So kind of got a lot that. But the punchline is we're definitely using all local sand, and I think in 100 mesh. The well -- the cost per well has come down a lot. And we've got a dedicated frac crew and execution is phenomenal, John. I would tell you that I couldn't be more pleased with what we're seeing there.
I mean, we're -- I think, in our presentation, you see our frac efficiency continued to increase 126% for first half of '18. So we're getting fracs away. And I think that's attributed to guys like my teams, our teams, putting the bit in the right spot and we're being consistent with that. And the execution in the field has been very, very strong. So that allows us to bring wells on faster, gives us confidence to build with our cycle times.
John White -- Roth Capital -- Analyst
And you're using a Halliburton frac there, right?
K. Earl Reynolds -- Chief Executive Officer
We are. We are, actually. We moved the Halliburton, late some time -- what was it late last year, Jim?
James M. Miller -- Senior. Vice President Operations
October.
Patrick Graham -- Senior Director of Corporate Finance
Yes, late last year and they've been our dedicated fracking, done a phenomenal job. I give them a lot of credit, one of the best-performing frac crews in the basin for sure.
John White -- Roth Capital -- Analyst
And finally, on selling the office complex. Are you going to move? Are you going to lease it back?
K. Earl Reynolds -- Chief Executive Officer
Well, John, we're actually -- we have a leaseback option there. So we'll be in the space for some time. Of course, we'll look at other options, right? So what we're doing is we're going to go from -- there's 4 floors here, we will be on 2 and then the counterparty will be, obviously, leasing of the rest of it. So we'll look at other options. We may stay or the other option or we'll definitely look at the space. And whatever make sense for our employee base and our needs.
John White -- Roth Capital -- Analyst
All right. Thanks again. Thanks John.
Operator
And your next question comes from Ron Mills of Johnson Rice. Your line is open.
Ron Mills -- Johnson Rice -- Analyst
Just a quick question. You haven't really talked about it much next year, except for -- except for really focused on getting to free cash flow. But in the current environment is, would the expectation be for us to assume remaining at a 3-rig case, and if so, what does a program look like if you're going to move all of that activity really focused on some of these larger spacing developments?
K. Earl Reynolds -- Chief Executive Officer
Ron, it's a great question. Look, one of the things I pride our team on, we've done a great job doing our planning. Scott and his team has done a phenomenal job looking at the obstacles to drill and do a really good job there. So we start looking at this, give or take 6 weeks ago in terms of what we think '20 looks like.
And so, look, I mean, our primary goal, I said in my remarks is to be cash flow neutral, and not really depend on capital markets here. So that's really what we're trying to drive it to. And so look, I mean, we'll look at staying at 3 rigs or 1 to 2. Obviously, that sets the dependency on the commodity and market. But what we're doing, and you heard me mention Come & Go. The Come & Go -- why am I doing Come & Go. That's all about trying to reduce cycle time, but also the benefits of the full section developments. Kind of a cube type development.
So that's an aspect of it. So the short answer is, we believe we can deliver at 2 rigs or 3 rigs, and that's going to be a function of what we decide with the book. But we think we can continue to give some production growth next year. And our goal, as commented, would be cash flow neutral. But no visibility right now to give you the quarter-by-quarter ideals, but our guys are planning it. We will be for sure talking about the back half of the year, as I mentioned, the Greenback.
So that's a full section development. And so if we're talking 6 to 8 wells, you're probably talking a couple of rigs occupied for a period of time. But then you'll be bringing on in Q1, I think, roughly, with our current view of it. But in terms of just will be a combination of partial section development, as potentially full section developments. But our ultimate goal is to be cash flow neutral. And as we get closer and closer to that point, we'll give you guys more visibility on it.
Ron Mills -- Johnson Rice -- Analyst
Okay, great. And then when you think -- when we think about the second half of the year and then -- and also when you think ahead in terms of relative economics, is it fair to assume that most of your activity even in 2020 will likely remain focused in Canadian and Kingfisher? Or do you, at some point, do you have to go back to Garfield?
K. Earl Reynolds -- Chief Executive Officer
Yes, good question. I would say that it's definitely fair to say and we said that in our remarks, it would be 100% in Kingfisher and Canadian in the back half of this year, of course. That's our expectation. Lots of reasons for that, primarily because of obviously economics that we're seeing in Canadian in both those areas. High oil percentage. I'm sure you're fully aware with activity going on in the basin, and rigs are falling. And if you think about where those rigs are falling, that's in areas where we really had very low oil percentage.
We're not seeing that kind of pressure in the oil window. But if I think about when we go back to Garfield, we're evaluating the timing of going back. I mean, obviously we had some great results in Garfield last year, and I'm really pleased with what we're seeing. When we look at in terms of delivering consistent returns, we feel like the best place to allocate capital today is in Kingfisher and Canadian County. But by no means that we're saying Garfield is not an investment opportunity for us. In fact, we're looking -- we got -- we shot 3D across all the acreage, and we're doing -- incorporating in those lines we have with our drilling program.
We've charged the G&G team with evolving the earth model just like we've done in other two areas. And I think that's going to pay dividends for us. And we'll -- based upon that work, we'll decide when we to go back and how much fracking we put there. But still pretty pleased with what we saw there, but we want to make sure we deliver the consistent returns always with respect to our capital program. And that's why we're focusing in Kingfisher and Canadian County in the back half of '19.
Operator
And this does conclude our question-and-answer session for today. I'd now like to turn the call over to Mr. Earl Reynolds for closing remarks.
K. Earl Reynolds -- Chief Executive Officer
Thank you, everyone. I really appreciate joining us on the call today. I just want to reinforce that -- and I think you've seen that we have a very strong team here at Chaparral. We've differentiated ourselves in terms of execution and our assets, and we can deliver strong results. It's very important that we do that on a consistent basis. And Scott and I, we look forward to speaking -- with meeting with you in the near future, and hope to see you at many upcoming conferences. Thank you so much.
Operator
[Operator Closing Remarks]
Duration: 36 minutes
Call participants:
Patrick Graham -- Senior Director of Corporate Finance
K. Earl Reynolds -- Chief Executive Officer
Scott Pittman -- Chief Financial Officer
James M. Miller -- Senior. Vice President Operations
Derrick Whitfield -- Stifel Financial -- Analyst
Jason Andrew Wangler -- Imperial Capital -- Analyst
John White -- Roth Capital -- Analyst
Ron Mills -- Johnson Rice -- Analyst
