Earthstone Energy, Inc. (NYSE:ESTE) Q4 2018 Results Conference Call March 13, 2019 11:00 AM ET
Frank Lodzinski - Chief Executive Officer
Robert Anderson - President
Mark Lumpkin - Executive Vice President and Chief Financial Officer
Scott Thelander - Vice President of Finance
Conference Call Participants
Neal Dingmann - SunTrust
Brad Heffern - RBC Capital Markets
John Aschenbeck - Seaport Global Securities
Ron Mills - Johnson Rice and Company
Joel Musante - Alliance Global Partners
Jason Wangler - Imperial Capital
David Beard - Coker Palmer
Good morning. And welcome to Earthstone Energy's Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation [Operator Instructions]. As a reminder, this conference call is being recorded.
Joining us today from Earthstone are Frank Lodzinski, Chief Executive Officer; Robert Anderson, President; Mark Lumpkin, Executive Vice President and Chief Financial Officer; and Scott Thelander, Vice President of Finance. Mr. Thelander, you may begin.
Thank you, and welcome to our conference call. Before we get started, I would like to remind you that today's call will contain forward-looking statements within the meaning of Section 27A of the Securities Exchange Act of 1933 as amended, and Section 21E of the Securities and Exchange Act of 1934 as amended.
Although, management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in our earnings announcement we released yesterday and in our annual report on Form 10-K for 2018.
These documents can be found in the Investors section of our Web site, www.earthstoneenergy.com, along with an updated corporate presentation. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially. This conference call also includes references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released yesterday.
Also, please note information recorded on this call speaks only as of today, March 13, 2019. Thus, any time-sensitive information may no longer be accurate at the time of any replay. A replay of today's call will be available via webcast by going to the Investors section of Earthstone's Web site, and also by telephone replay. You can find information about how to access those on our earnings announcement released yesterday. Today’s call will begin with remarks from Frank, providing an overview of our activities and future plans, followed by remarks from Mark regarding financial performance and matters and concluding with remarks from Robert regarding our operations.
I will now turn the call over to Frank.
Okay. Thank you, Scott. And thank you for all of you folks that are on the line. We made great progress developing our Permian Basin assets in 2018 and have high expectations for 2019. Before we get into the details, I'd like to remind you that a couple of weeks ago, we put out a press release related to our reserves and also tell you that yesterday we posted and updated our presentation for the company as a whole on our web page.
In that presentation I’d like to refer you to page eight in particular to demonstrate the progress that we have made over the last couple of years. Using 2016 as a base in 2017 and 2018 we increased our average daily production by over 260%. We have increased our adjusted EBITDAX five fold, we have cut our lease operating expenses in half and we’ve lowered our G&A per BOE by about 10%.
We - our expectations is that we can continue to do those types of things, at least that we're working very hard to do so. We've accomplished all of them in a couple of years while ending up 2018 with a debt to adjusted EBITDAX ratio of 0.8 to 1. So we're under levered strong cash flows and looking forward to '19.
During '18, we substantially increased our proved reserves and production and as mentioned, we've reduced our administrative costs and LOE on a per unit basis. We've also increased our efficiencies and our drilling and completion operations and we are targeting free cash flow in 2020, if not before.
Our balance sheet remains very strong and we have substantial liquidity. We've set our 2019 capital budget at about $190 million, which assumes 1 rig operated program and non-operated activities as they are currently proposed by operators. We also have some minor activity in our operate at Eagle Ford.
As we've demonstrated in '18 we will continue to effectively exploit our asset base while we enhance our acreage and increase production through acreage trades drilling and completions and acquisitions that will continue to allow longer laterals and even greater efficiencies. And of course, we'll continue to pursue significant transactions to build scale and market relevance.
But I do want to stress that we will also remain capital disciplined and only pursue acquisitions that we believe will create substantial value for our shareholders.
I'll turn this call over to Robert to provide some added highlights then Mark will discuss financial matters and Robert will follow-up with details on operations. Mark. Robert, I'm sorry.
Thanks, Frank. A few highlights from last year. Our 2018 total net production grew 26% over 2017 volume to 3.6 million barrels of oil equivalent just under 10,000 Boe a day. Our proved reserves grew 24% to $98.8 million Boe from $80 million Boe at the end of 2017, primarily through the drill bit with approximately $22.3 million Boe of proved reserves added from extensions, discoveries and revisions.
The efficient development of our quality acreage allowed us to generate a significant increase in adjusted EBITDAX which grew to $96.2 million for the full year 2018 versus $60.6 million in 2017, an increase of almost 60%.
Based on our capital expenditures for development activities our extensions and discoveries of 16.2 million Boe in 2018, resulted in a finding and development costs of just $9.49 per Boe of proved reserves. And our overall finding and development costs including acquisitions amounted to $7.79 per Boe of proved reveres.
As we evaluate what we've learned in almost two years of operating our position in the Permian, we are pleased with the well performance and the quality of our acreage position and are targeting even greater operating improvements and efficiencies. We expect to build production without proportionate increases in fixed operating and administrative costs, which will continue to drive down costs on a per Boe basis and increase margins.
We continue to work on our acreage position to accommodate longer laterals and increase our operative footprint. As an example, for 2019 we expect to complete wells with an average lateral length of close to 9600 feet, which will be more than a 20% increase in lateral lengths compared to 2018 completions. And our 2019 completion program is somewhat back end weighted. And as mentioned, we expect to be able to cross into free cash flow territory in 2020 based on a one rig, Midland Basin program with moderate non-op activity and assuming a similar commodity prices we are currently experiencing.
With that said, I'll turn it over to Mark for a review of our financials.
Thank you, Robert. Looking at our financial metrics for the quarter and starting with the top line revenues of $41.2 million were up 16% over Q4 2017 and down 11% sequentially compared to the third quarter of 2018. The sequential revenue declined was due largely to a decline in realized prices in the fourth quarter compared to the third quarter. Our fourth quarter 2018 production of 10,454 boe per day was favorably impacted by approximately 1100 boe per day of production that was shut in across 11 gross operated and three gross non operator wells during the periods due to offset completion activity.
We're projecting that production for 2019 will average approximately 11,000 to 12,000 boe per day, which is an 11% to 20% increase over 2018 results. Our production mixture in the fourth quarter reflected a higher crude component at about 70% crude with NGLs coming in at about 17% and natural gas making up the balance. This compares to our mix for full year 2018 of 65% oil, which is in line with our other 2019 expectations for a mix of about 65% oil, 19% NGLs and 16% natural gas.
We reported fourth quarter 2018 net income of $81 million or $1.26 per share. Fourth quarter net income includes a $96 million unrealized gain on the mark-to-market hedges and $12.6 million in transaction costs largely related to our proposed transaction with Sabalo Energy, which was terminated in December. For the year we reported net income of $95.2 million or $1.58 per share.
Adjusted EBITDAX, as we define it reported was $23.9 million in the fourth quarter of 2018, down from 26.4 million in the third quarter and up from 22.1 million in the fourth quarter of 2017. For the full year adjusted EBITDAX grew 59% to 96.2 million from 2017, $60.6 million.
LOE per BOE for the fourth quarter was $6.25 for full year 2018 LOE averaged $5.66 per BOE continuing a downward trend compared to $6.84 per BOE in 2017. We anticipate average LOE per BOE in 2019 of $5.25 to $5.75 per BOE and are continually striving for improvement.
Our G&A excluding stock based compensation for 2018 was just over $21 million relatively flat versus 2017, $20.5 million. This includes a fourth quarter accrual of $2.4 million for annual cash incentive compensation that was paid out in the first quarter of 2019 but accrued as an expense in the fourth quarter 2018.
Our G&A per BOE metrics, excluding stock based compensation average $5.81 per BOE for the full year. We are presently guiding for a projected G&A per BOE in 2019 of $5 to $5.50. We do continue to focus on managing our cost structure as efficiently as possible.
Now moving to the balance sheet and liquidity. During the fourth quarter, we closed on the acreage trade and acquisition and rig accounting for approximately $28 million. This was largely fund with additional borrowing from our credit facility which November saw the borrowing base increase by $50 million, up to the current $275 million borrowing base. At December 31, 2018 the company has outstanding borrowings under the credit facility of $78.8 million in cash balance for approximately $0.4 million. This leaves us with almost $200 million of undrawn capacity on our credit facility, so our liquidity remains very strong.
Our capital expenditures for the fourth quarter totaled $41.4 million, resulting in full year capital expenditures of approximately $153.2 million excluding acquisition. As Frank mentioned, in 2019 we expect total CapEx to be approximately $190 million.
We're very well hedged with favorable prices for 2019 and 2020 with awesome place for 2019 on 84% of the midpoint of our 2019 old guidance and an average price of $65.67. And we got a decent bit hedged in 2020 at even slightly higher prices on the oil side.
So with that I'll turn it over to Robert to review operations.
Thanks. As we've highlighted we're proud of our operational accomplishments in 2018 and in 2019 we will continue to focus on effectively executing our run rate program. During 2018 we maintained a one rig programs throughout the year and drilled 16 wells with an average working interest of 89% and we completed 19 wells in Midland, Reagan and Upton Counties with a 79% average working interest. These wells targeted multiple formations including the lower Spraberry and Wolfcamp A, B and C intervals with an average lateral length of 7900 feet.
Our well performance on average is in-line with or exceeding our tight curves and is expected to generate attractive well level economics in the current commodity price environment even before considering our oil hedge position averaging close to $66 per barrel in both 2019 and 2020.
In the fourth quarter we completed 8 gross 6.7 net wells, including 3 gross wells were completed in late December. We ended the year with 6 gross 4.2 net wells in progress, which includes both operated and non-operated activity, all of which are now online and producing.
Let me highlight a three well pad we completed in Western Reagan County in late December. It is our Sinclair unit where we hold a 93% working interest. The average lateral length of those three wells was 6,883 feet and the wells were completed in the Wolfcamp A, B upper and B lower. These wells offset two existing Wolfcamp B wells, with the closest offset being approximately 775 feet in the same target. After about 70 days in production, the new wells are still increasing in rate and have not hit their peak 30 day rates yet.
We have experienced this in the past and it's quite common with Wolfcamp A completions, but extended time to peak rates on the Wolfcamp B zones is likely due to the existing Wolfcamp B producers in the unit which have been producing since May of 2017.
Although these three new wells are still cleaning up, current 30 day rates are ranging from 400 to 800 Boe per day with oil cuts of 78% to 88%. They are starting out at a little lower rates than the prior wells however, two of the three wells are performing in line with our expectations.
For instance the B upper well is tracking the two original completions. Although those, these two original completions have only been producing for around 20 months, we expect them to average an ultimate recovery of approximately 110 barrels of oil equivalent per foot.
I will also note that the two original wells were shut in during the fracking of the three new wells that are now back online and producing as expected.
Our takeaway from these results is that we are still evaluating our operations to determine the parent child well issues as it relates to optimum spacing between wells, co-development of multiple benches and frac design when completing new wells and existing units. Each area and each bench will be somewhat unique. We are however comfortable with 660 foot spacing in certain areas and recognize that we may need wider spacing in other areas in order to achieve acceptable economics. These lessons and what we've observed from industry well data are driving decisions for our future development program. The good news is that we have not been aggressive in our spacing practices nor in the number of ventures we can complete economically.
Having operated our Midland Basin asset for close to two years now, we are seeing tangible improvement in operational metrics, as our team is focused on maximizing efficiencies, and reducing costs on both a relative and absolute basis.
If you refer to our presentation on our website, page nine has similar statistics that I'm about to go through. We've been able to achieve significant cost reductions in drilling completion and production operations in 2018 by improving the efficiency of our operations. We drilled the last eight wells in 2018 from slide rig release in an average of 15.3 days, with an average completed lateral length of a 8632 feet, which is a 30% reduction in time compared to the second half of 2017, despite increasing the lateral length by 11%.
On the completion side, efficiency gains were even more substantial. In January 2018, we were completing multi well pad at 5.7 stages per day but by year end we were up to 8.2 stages per day, a 44% increase in stages per day. And we recently finished fracking a two well pad averaging nine stages per day.
From a cost standpoint, our last three wells completed in early 2019 averaged an all-in frac costs under $62,000 per stage, which is down from 85,000 to 90,000 per stage last summer driven by both our improving operating efficiencies but also cost reductions from our shift to using more in Basin sand.
For our operated program, we expect to about 16 wells in 2019 with an average working interest of 85% while completing 13 wells with an average working interest of 86%. Our 2019 focus is on the Wolfcamp A and B zones which have proven results across our acreage position.
Currently, our rig is in Midland County drilling five Wolfcamp wells in our mid stage unit, where we have a 67% working interest. We are also participating in a two Wolfcamp wells just offsetting this unit where we have a 35% working interest. All of these wells will be approximately 10,000 foot laterals, as a direct result of land trades we did during 2018.
We have completed three wells so far in the first quarter of 2019, two in Upton County, each with 100% working interest that are beginning to flow back and one in Central Reagan County that has been online for less than 30 days where we have an 89% working interest. So first production days for the remaining 10 operator wells expected to be online over the balance of 2019 are the five Midland County wells in the third quarter and then the final five wells in November and December of this year.
We expect production growth in 2019 will result from a total of 16 new wells including the three Sinclair wells that came online right at the end of 2018.
And we plan to end 2019 with four gross 3.4 net operated wells drilled and waiting on completion. As mentioned, our 2019 capital budget is $190 million, which includes $118 million for our operated Midland Basin one rig program and $47 million for non-operated activity in the Midland Basin.
We're also targeting $10 million for our operated Eagle Ford activity. Given the second half weighting of our completions approximately $50 million of our 2019 capital is applicable to production growth for 2020 rather than 2019 which should pop position us really well to end the year and begin 2020.
We will continue to pursue acreage trades in the Southern Midland Basin with the intent of increasing our operated acreage and drilling inventory, with a focus on longer laterals and realizing grading, greater operating efficiency.
Our strong balance sheet supports potential acquisitions as well and as we have demonstrated we intend on being strategic and disciplined in pursuit of growth. We have an attractive acreage position and corporate level returns will benefit from our efficient operations and our hedge position.
As I have already mentioned, our program is currently designed to reach positive cash flow in 2020 under a one rig program and current commodity prices while maintaining our low leverage profile.
Frank, do you want to wrap this up?
Sure we've said it twice and I'll say it a third time we are targeting positive free cash flow. We're also highly aware of the market concerns about the so called parent-child effect on well economics. I want to point out specifically that our acreage positions are very lightly drilled. And we continue to evaluate both industry results and our practices in order to mitigate the effects of our prior production on new wells.
Once again to be redundant based on our results today we believe our location count and type curves are reasonable and achievable. Finally I want to stress that our fundamental practices for more than three decades in multiple basins have been to control those items that we can on a daily basis.
Meaning to maintain a strong balance sheet and focus clearly on effective and cost efficient operations that generate good shareholder returns. We'll continue to work diligently to increase our scale through acquisitions and mergers, but only if transactions are accretive and provide value for our shareholders.
Thanks for listening to our prepared remarks. And now operator we'll take any questions.
Thank you. [Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust. Please proceed with your question.
Good morning guys. Robert, my question's for you. Could you talk a little bit about how you plan to that, I know you mentioned this sort of cadence, but how you plan to sort of cluster the wells going forward like you have in the past?
Sure, Neal. Like I said, we've got five wells in Midland County, we're in the process of drilling right now those all be completed at one time and then the last five well we get completed this year will probably be a three well area and then a two well following that in a little bit separate area. So again, that's how part of our completion efficiency works is that we don't try and do one-off well we try and do them in groups or batches. And definitely on a pad basis you've got to do that. But that's the way we planned out our year.
And then could you talk maybe Frank, just about your through about organic growth versus M&A if free cash flow had been a bit better than expected?
Well, Neal you've known us for a long time. I’ll try to do this is tinkering. Our primary focus on a day to day basis is to do acreage trades and acreage and maybe smaller acreage acquisitions that block up some of our current acreage positions and move to longer laterals. You can see that, I think we've achieved. Although we have somewhere, where there's - I’m babbling . There's a presentation in our web page that shows what our inventory is by lateral length. And I think if you compare that to prior that we put out there, you'll see that our count towards longer laterals is improving. So we're going to do that on a daily basis.
We are in the market everyday to look for larger accretive positions, whether that's M&A or whether it's large acreage acquisitions. The trick there of course, is to build a scale that the market and the analysts are looking for without over leveraging the balance sheet and that's easier said than done. But we're at it every day. We had a great acquisition last year and unfortunately in the fourth quarter had a perfect storm. So we're not going to do something and just over leverage the company, but I don't know how to answer that any better, Neal.
That's spot on. Thank you all.
Thank you. Our next question is from the line of Brad Heffern with RBC Capital Markets. Pleased proceed with your question.
Hey, good morning, everyone. Robert, I wanted to dig in a little bit more on the Sinclair unit. It sounded like maybe it's the B Lower well, that's the one that's not performing on type curve. So, I was just curious if you have any thoughts about having two targets in the B or whether that test makes you think that maybe there's only one in sort of a full field co-development mode.
Brad, you know that’s, that is quite possible, but we're still trying to figure out if you adjust spacing, maybe you do decrease the total number of wells but you still have multiple targets within the B. It's definitely thick enough where we can see the oil in place and the ability to go drill two wells, again, it's just how close they are together.
Okay. Got it. And then I guess on the other side of the M&A question, I guess any new thoughts about the Eagle Ford and how it fits in longer term.
We continue to consider that every day, we're not going to expand in the Eagle Ford, we will maintain our acreage position or the preponderance of our acreage position. There is some offset activity that from a production standpoint and from some lack of a better word science that was put on some of those wells looks encouraging. We have a small program that is like $10 million or $11 million. I don't see us putting a lot of money into it, I don’t see us right now being an aggregator in the Eagle Ford, you know pending commodity prices offset activity, it will likely become a divestiture candidate at some point.
Okay. And then one more if I could sneak in and just on the LOE for the fourth quarter, with certainly elevated versus the third quarter on a per Boe basis. I was just wondering what that was doesn't work over there obviously it's higher than the guidance for 2019? Thanks.
I think part of that Brad was a relative, the relationship of how much our vertical wells cost and the trades that we did ended up with some of that causing us a little higher LOE in the fourth quarter. There's nothing that stands out where we had an unusual work over expenses or anything like that.
Thank you. The next question is from the line of John Aschenbeck with Seaport Global Securities. Please proceed with your question.
Good morning everyone, and thank you for taking my questions. For my first one Robert, I was hoping to follow-up on your remarks on parent-child. Well, interference and just curious if your ultimate conclusion there is that you need to move to a multi zone development going forward. How quickly could you flex your plan? I suppose the limiting factor would be drilling obligations? And then also how do you think about feathering and tests and some of your less delineated intervals, if you do pursue kind of a multi zone development going forward?
John, we do have some obligations this year, and they're built into our plan obviously. We are fully developing the A and B in our Midland County asset where we operate and so that'll be completely drilled up.
And so we're taking it into account where it makes sense but it won't happen this year in terms of a co-development of multiple benches. The Sinclair was a good example for us to test, three benches in an area where already had two wells producing.
So it's a 2020 event where and we're already starting to plan on certain areas where we would co-develop and drill five wells and some kind of pattern and trying to figure out how to mitigate the parent-child relationship and ultimately hurting the existing production and while maximizing the new wells is all also.
Regarding testing we feel pretty strongly that the three benches for instance in Reagan and Upton County that A and two benches in the B all have good economics and we're going to just stick with those three we're not going to do any testing but we also recognize that certain benches in certain areas like up in Midland County where we might have a middle Spraberry and one of our blocks of acreage could be developed later or the Wolfcamp D and Reagan County with some recent results that look really enticing could be developed at a later time without being influenced by the existing parent well or whatever development we have out there. So we're not planning on doing any testing we're going to stick to what we call the money benches and develop those for the foreseeable future.
Okay, got it, great. That's helpful appreciate it. For my follow-up, I was hoping to dig a little deeper into some of your comments regarding achieving free cash flow in 2020 more of a conceptual question if you will in that. I know the concept of free cash flow has gotten a lot of press in the industry recently, but it's certainly not the be all end all value creation. So just curious, Frank, Robert, Mark when you guys think about Earthstone today and where it is in its business life cycle, how important is reaching the state of free cash flow generation as opposed to maybe the benefits of continuing to grow add some more scale at the business and then increase your future free cash flow generating capabilities. Thanks.
Well you know, that's - okay, this is Frank. So if I had my druggers, I would keep on building a value provided however that we didn't get into the trap of being over levered that so many of our
peers have unfortunately experienced. That said after more than three decades of being an independent in 45 years. We're not smart alecky enough to preach to the market. So if the markets want free cash flow, we're going to work really diligently to get there. While we continue to block up our acreage, increase our inventory develop, perhaps a prove up over time, additional benches, solve this parent child relationship such that when the market perceptions change and the staffing here such that when and if market perceptions change, we can bring on that second rig or that third rig or whatever have you.
But right now, it's the old adage of not trying to sell ice to Eskimos.
John, its Mark. I'll just follow up with a couple of comments. One is just rest assured that we're thinking about how to create shareholder value every day and clearly in the last year so the focus on free cash flow from investors has been heard by all E&P companies large and small. Certainly not all E&P companies have all the same characteristics. And we don't think that, we cut our drilling program tomorrow and achieve free cash flow. But we don't think that's a panacea for all that could possibly ail the E&P industry.
To your point of well if you have a little more outspend you've got more cash flow per share in a few years versus otherwise. You know part of the math would seem to say that well, investors are asking for free cash flow in order to have a similar stock price. They've got to trade at a couple -- at a higher multiple in a couple years. We don't know what it looks like in a couple of years and certainly the industry is digesting that this earning season we've seen plenty of guys cut and maybe experience some frustration what's the reaction from investors initially how that plays out over two years, maybe a different story. But we're thinking through this every day and looking for the best way to create shareholder value. We don't know what that is in 2020. We know we're positioned to with a lot of great options in terms of with our program, what we think will be free cash flow positive, but we certainly have a great inventory and continue to learn more about our asset improve operations where whether it's organically or through acquisitions. There's other things that we got the options of doing.
Okay, great. Very well said. That's it for me, I appreciate the color and the time. Thanks.
Thank you. The next question is from the line of Ron Mills, with Johnson Rice and Company. Please proceed with your question.
A couple of questions, really follow-ons to earlier ones. I just want to make sure I understand on the parent child issues Robert. You're referencing not just spacing with each within each formation, but also relative spacing between the different formations where there's A or the upper or lower B is that fair representation?
Yes, it is Ron, we worry about vertical spacing as well as horizontal in a horizontal sense too so not only 660 feet between two wells in the same bench, but what is that distance between an A and a B upper and B upper and B lower and we're going through that exercise with things we're doing and learning and then what the industry is telling us as well in terms of their data.
And in reference to the earlier question about the lower B on the Sinclair pad, in your response you talked about you still think the lower B is thick enough to support a couple different laterals. And as you go back and review the at least early data there? Is there something about the targeted lateral zone how is your lateral target compared to any offset operators that may be in the area and how can you go back and optimize that in future activity?
That's a good question but we have been pretty consistent about where we're landing our wells and every area is a little different just because of the geology local to an area in this particular area we landed our lower B in the same as the original lower B well same with the upper B. So there's nothing different about that. Again it's just how widely spaced do wells need to be. I'll make one kind of global comment is that, we have a large number of sticks we have a lot of locations. Obviously not all those are proved and our proved undeveloped locations are puds, are a lot wider spacing than 660 feet.
So if we determined down the road that that is too tightly spaced it doesn't affect our proved reserves in any event at all.
Ron as you as you know by knowing us over the years we've never been quote unquote aggressive in our reserves or our stacks we think these are reasonable and achievable but this is an issue that you just can't wake up on Monday and have solved. With all the drilling and different areas and slightly different geology and so forth all I wanted to do was point out that we are very cognizant of it we don't think we have been aggressive in the information we put out there and let you guys know that we're studying it every day.
Great and then just when I look at Slide 14 of your presentation where you have your inventory then on those gross locations that includes both booked and unbooked locations right Robert?
It's proved and non proved locations that's exactly right.
And do those locations or I know you're proved you said are still booked well above the 660 foot spacing but when we look at this particular table should we assume from a from proved and non proved standpoint you move down to 660 or is that unfair?
In general terms this layout of number of locations is based on 660 foot spacing.
Okay, great thanks. And then Frank as it relates to acquisitions you the Sabalo deal was, this one where you, I think you were kind of going down the path where, hey, we have our balance sheet we're not afraid to use it for the right kind of acquisition as long as there's line of sight to get your leverage ratio back to an acceptable level for you within a reasonable timeframe. So given the what happened with commodity prices since then, and walking away from that deal, I assume that's not the only deal in the basin that suffered a similar fate due to pricing. So if you had to weigh an opportunity set for larger transactions, how does it look today versus even you know, five or six months ago when you were set to announce that past deal?
Well, I'll say that probably changes out there every week or the sentiment changes. I'll say that there's a lot of things that we like to chase there's some that we are chasing, none of which were as large as the transaction we were on. It's all the matter of buyer and seller sentiment and the secondary matter is that we're not going to let our balance sheet get out of control. So
I just can't tell you we have to find some deals out there that have a good production component because the last thing we're going to do is buy 20,000 acres on debt, right. A non-cash flowing asset on debt. So we're just on it every day. We're working hard on stressing to folks that we have a long track record that the core I shouldn't say the core with Mark here that the longer term executives that have been together have done this repeatedly over time. That we brought in folks like Mark and Scott and others that we can double our production without doubling our G&A. So we're out there every day. I don't know what else to tell you.
Thank you. The next question is from the line of Joel Musante, with Alliance Global Partners. Please proceed with your question.
Hey, good morning, everybody. I just had a question on the, -- given to your back end weighted development program, I was just wondering if you can give us an exit rate for the year what that might look.
Hey, Joel. Since we’ve known each other so long, I'll just say no, I was going to say higher. Okay, that's good. Higher than this year.
Joel I would say directionally, and we're not give what an exit number is. But directionally with the backend weighting there's fairly flat to moderate growth the first half of the year and the quarterly production rate and we expect that to start growing a bit more substantially in the third and fourth quarter.
Okay, and do you foresee any maybe you know downtime from offsetting completion activity
during any period?
Well, you would have to kind of factor that in. And I think we’ve built in a little bit of lag just some general lags into our models. Our models are dependent of course on commodity prices availability of high quality services and we can't really forecast at all when some offset operator is going to be fracking that we have to it's just a situation that all of us in the industry have to deal with, it's an unpredictable situations.
We do think we have a much better kind of handle on that and what it might look like on average, the fourth quarter, no doubt, was a bad confluence of events that led to the 1100 Boe per day, that was shut in, due to offsetting fracs.
With the guidance that we put out in January, we did embed some risk factor into that, that we clearly hadn't done a very good job of before. And, as Robert mentioned, we've been operating this assets for less than two years. And if you think about that, in 2018 was the first full calendar year we were offering the assets. Operationally we've continued to improve. And really from a modeling standpoint, we understand the asset better and what can go wrong and we think we've accounted for that in an appropriate and reasonable manner in our guidance.
The other I'll say Joel is where our plan is this year in terms of physical locations at least as far as it relates to our own properties and where we're going to have to shut in our own offset producers. We have limited number of wells or that's the case. We could get some issues from offset operators who frac well, you know have some impact on us and that's where we're going to have limited line of sight on when that could occur.
So Robert for Joel and whom else is out there at Mid-States, where we're going to have five wells and we're going to start fracking when?
Abut June. Right now we don't see problems associated with those right.
And just depends on what offset guys are doing?
So that could be delayed, it could be shut in it could be whatever. That's just for the issues that the industry has to deal with particularly as smaller companies out there.
Right. Right. Okay. And then, just one last one. You mentioned that, if you're you want to achieve cash flows neutrality and that would be based on a similar program next year to this year, does that include the nonop activity, or is it just operate?
It includes nonop activity at a lower CapEx in 2020 then this year. We kind of think that this year is a little bit of anomalously high. But again, we have some good nonop assets and in 2020 rolls around and somebody says, hey, we want to get drill, 10 wells in a particular area will look at the economics and make sure it makes sense and if it does, then we will participate in our capital expenditures will be higher than kind of what we're a normal run rate whatever normal is.
Yes, we think we think that $45 million to $47 million for nonop this year is may be high on a continuing basis. And, Joel, no guarantees, but you look like back end whatever it was September October we did that that trade of nonop for op. We're always looking to increase our op position. We like operating, as you know and maybe some of the trades we can do this year or enhance that so we'll be more solidly in control of our capital budget.
But then like Robert says the nonop stuff is looking pretty good and we'd be shooting ourselves in the head this year if we didn't participate.
Okay. Yes, look like, it was pretty high work and interest. All right, well, thanks a lot. Appreciate it.
Thank you. Our next question is in the line of Jason Wangler, with Imperial Capital. Please proceed with your question.
Good morning, guys. Maybe to dovetail on Joel’s question on the non-op side. Is a lot of that the acreage capture perhaps or is it just simply some opportunities that are there from the operators and you guys are coming along that makes that number maybe higher than as you look at 2020 or beyond.
It's where an operator has gotten around to certain trades or what have you in order to drill, 10,000 foot laterals and the ability to go out there now and implement it in their plan, that's in one particular case. The other case where we have a big acreage block and we're participating and again it fit into their planning cycle and its happening this year.
Yeah, so I don't think -- I don't know what you mean by acreage capture. But this is not this is, for lack of a better word. This is discretionary or optional on our part, but it's good areas and things that we want to participate in.
Okay. So it's more of like you said, it's more of a timing thing. And it just happened right now.
And Robert, on the operated side, obviously it's a few months off, I guess. But as you look at the completions and things I'm assuming that it's pretty easy to kind of get in into a calendar and things now, but how do you kind of think about setting up the batch completions and things as they are few months off going into later this year, is there, -- can you get those plans now, or just kind of the thought process there to kind of get them in line with your expectations.
No, they’re planned. We work very closely with one frac company to integrate our timing with their schedule and make sure that we've got it nailed down pretty as close as possible. I would say that if oil prices all of a sudden skyrocket, their demands may go up, but my guess is they have a pretty full schedule for the full year of a frac fleet and they know when our schedule and there's the timing works out. So we plan the whole year out with the with the frac company and the other service companies
Okay, I appreciate it. I'll turn it back.
Thank you. [Operator instructions] Our next question is from a line of David Beard with Coker Palmer. Please proceed with your question.
Hey, good morning gentlemen.
Maybe just going back to the well count and any color you can give relative to spacing assumptions in your well inventory. I think you mentioned somewhere at 660 foot, but the puds were wider than 660. So I was really confused and maybe what percent of your inventory is at 660 or if you're looking at spacing between zones what that just to give some color there so that we just better understand the assumptions behind the 866 gross well locations.
David, this is Robert. I'll tell you that when we put out our reserves press release a couple of weeks ago I think we said in here that there's a 100 -- I'm going off memory 189 pud locations. So I think you could do some math there to kind of back into what that means compared to the 860. It's much wider spacing than we’ve even drilled wells on for our puds. And that's about all I'm going to say on that 660 is the absolute eight wells across a mile and our puds are obviously spaced at much wider than that.
Thank you. It appears there are no further questions at this time, so I'd like to pass the floor back over to Mr. Lodzinski for any additional concluding comments.
The only concluding comments are, thank you, we're always available to answer questions and thank you for calling. And with that we'll shutdown.
Thank you. Ladies and gentlemen, this does conclude today's teleconference. Again we thank you for your participation and you may disconnect your lines at this time.