Good morning, and welcome to the Magnolia Oil and Gas Corporation's 4th Quarter 2018 Earnings Conference All participants will be in listen only mode. Please note this event is being recorded. I would now like to turn the conference over to Brian Kurellis, Vice President, Investor Relations. Please go ahead.
Thank you, Anita, and good morning, everyone. Welcome to Magnolia Oil and Gas' Q4 2018 earnings conference call. Participating on the call today are Steve Chazen, Magnolia's Chairman, President and Chief Executive Officer and Chris Stavros, Executive Vice President and Chief Financial Officer. As a reminder, today's conference call contains certain projections and other forward looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements.
Additional information on risk factors that could cause results to differ is available in the company's proxy statement filed with the SEC. A full Safe Harbor can be found on Slide 2 of the conference call slide presentation with the supplemental data on our website. You can now download Magnolia's Q4 2018 earnings press release as well as the conference call slides from the Investors section of the company's website atwww.magnoliaoilgas.com. I will now turn the call over to Mr. Steve Chazen.
Good morning and thank you for joining us today. I'll provide a brief overview of our business and Chris will go into some of the details of financials and also provide some additional guidance before we take your questions. As we stated from when we started this almost a year ago, Magnolia's business model is designed to be differentiated and the primary objective being to generate stock market value over the long term. Our company's continuing strategies exhibit characteristics that appeal to and attractive generalist investors. These attributes include generating actual earnings and significant free cash flow with moderate growth and low levels of debt.
While Magnolia has only been in business for a little more than 6 months since closing the transaction with EnerVest last July, we have exceeded most of our original business plan objectives during 2018. Our Q4 2018 production averaged nearly 62,000 BOE a day and at a rate that was more than 30% higher than our original full year guidance. Our higher than forecast production growth was due to stronger than expected well performance, drilling efficiency gains and higher non operated activity. We emphasize that much of this was accomplished by averaging roughly 2.5 rigs and utilizing 1 completion crew throughout the assets over the balance of 2018. I'd like to also point out that our production in Giddings has doubled since we assumed ownership of the assets.
Our double digit organic production growth since the closing of transaction was achieved by spending approximately 57% of our EBITDAX on drilling and completing wells and was well within our business plan. Significant portion of free cash flow generated by the business during our 2018 ownership was used to make bolt on acquisitions, which further strengthens our core operations in both Karnes and Giddings. Most notably during the Q3 of 2018, we acquired substantially all the South Texas assets of Harvest Oil and Gas Corporation, which added both production and drilling inventory to our Karnes County and Giddings assets. Additionally, in the Q4, we added to our Karnes position, acquiring approximately 18.50 net acres. Generating high pre tax margins is another characteristic of our business model.
Our EBIT margins were 26% during the period we owned the assets in 2018, including 29% in the 4th quarter or 35% on an adjusted basis for the 5 month period. We accomplished these objectives while maintaining low financial leverage and strong liquidity, including a $550,000,000 undrawn credit facility and a cash balance that grew by approximately $100,000,000 during the Q4. As we move forward through 2019, we believe that our strategy and business model is well suited and flexible for the current environment. Current product prices are above or even a little higher than the levels that we when we first announced the transaction nearly a year ago. We view this environment as one in which we can thrive.
While we have been running 2 rigs in Karnes for most of the first quarter, we plan to release 1 rig by the end of the quarter in order to adjust our capital levels to lower product prices. As a result of our higher operated and anticipated non op activity, our capital as percent of EBITDAX is expected to run a little hotter than normal during the Q1. This rate is expected to normalize towards midyear as our activity levels adjust to product prices. We will continue to evaluate our drilling activity as the year progresses. Despite the reduction in our operated rig activities, we still anticipate growing our production at a double digit rate during 2019, while spending within 60% of our EBITDAX.
Importantly, our goal does not solve for growth rate, rather the growth rate is simply the outcome of our capital program. The rate of the capital required to achieve this growth rate speaks to the quality of the assets. In Karnes, we continue see high quality well results, which remain fairly constant and steady and with a predictable outcome. We see ample opportunities here for small to midsize bolt on acquisitions to further strengthen our position over time. In Giddings, while the increase in our production is related to the quality of the wells drilled, the results continue to be quite variable.
Our current plan is to run 1 rig in Giddings and continue to drill some appraisal wells to help improve our understanding and further delineate our size position where we have approximately 650,000 gross acres. Our Giddings acreage is almost entirely held by production. Finally, we're continuing to build out the Magnolia staff, adding several key technical administrative positions, which should gradually enhance our asset performance. We are still in the very early stages of the company. We're pleased with the performance of our assets and what we've accomplished so far.
We remain very optimistic regarding our prospect of opportunities in 2019, which will allow us to continue to deliver on our business model objectives and create value for Magnolia's shareholders. I'll now turn the call over to Chris Stavros.
Thank you, Steve, and good morning, everyone. Before I walk through some of the numbers, I'd like to point out a few items that may help in understanding our financial statement disclosures. First, the Q4 ending 2018 was the 1st full quarterly period under which we own the assets since we closed the transaction with EnerVest at the end of last July. 2nd, we'll refer to the 5 month period from the end of July 2018 through the year end as the successor period of ownership. Keep in mind that our financial statements for the successor period lack comparability with predecessor period financial statements prior to that date.
Finally, we adopted the new revenue recognition accounting standard ASC 606 at the end of 2018 for the successor period using a modified retrospective approach. While adoption of the new standard is not anticipated to have a material impact on the company's net earnings or EBITDAX, there was a small positive impact to our natural gas and NGL production volumes and this also contributed to the slightly lower percentage of oil in our production mix. Our reported production volumes for the 5 month successor period of ownership reflect this adjustment for the adoption of the new standard. My expectation is that our financial statement disclosure should be easy to understand and more consistent as we move through the year. Moving on to some of the numbers, referencing Slide 5 on the conference call presentation that's posted on our website, we reported GAAP net income attributable to Class A common stock of $33,000,000 or $0.21 per diluted share for the Q4 of 2018.
Total reported net income for the period which includes the non controlling interest was approximately $58,000,000 or $0.23 per diluted share when including the total of both Class A and Class B common stock outstanding. Investors and analysts should use this latter measure of EPS when comparing us to other similar companies. Turning to Slide 7, our total production averaged 61,900 MBoe per day during the Q4, an increase of more than 5% sequentially and ahead of our previous guidance. 4th quarter production in the Giddings field was 20,600 MBOE per day or a sequential increase of nearly 22%. The higher than expected production at Giddings for the 4th quarter is driven mainly by new well completions in addition to a full quarter benefit of the production from the Harvest acquisition.
Our Giddings volumes have approximately doubled since we announced the original transaction nearly a year ago as Steve mentioned. We remain very optimistic about our prospect of opportunities in the field. Our revenues totaled $255,000,000 in the 4th quarter benefiting from both higher volumes and strong oil price realizations which averaged $65.12 per barrel during the period and is shown on Slide 8. Although oil prices declined sequentially throughout the Q4, our realized prices remained relatively strong as we are indexed to export market prices on the Gulf Coast. As such, our oil realizations were 110% of WTI and more than a $6 per barrel premium during the Q4.
Turning to costs, our LOE during the 4th quarter was $3.46 per BOE and higher than the Q3 2018 2 month successor period. We expect these costs to trend slightly lower through the year and as our production volumes continue to grow. Our Q4 DD and A was $19.65 per BOE and reflects Magnolia's plan to focus on near term development of PUD reserves. 4th quarter G and A expenses were up $18,500,000 or $3.25 per BOE. These costs increased sequentially as we continue to build out our corporate structure, IT systems, as well as incurring some organizational startup and other related expenses.
We estimate that our per unit G and A costs in 2019 should be similar to 4th quarter levels. Our total reported net income for the Q4 included $2,200,000 of transactions costs related to the original acquisition. We show these fees as an adjustment to our net income on Slide 9 of the presentation. These consulting and other service related costs are expected to dissipate through this year. The effective tax rate was approximately 12% in the 4th quarter and we expect the 2019 rates be in the range of approximately 12% to 15% due to the accounting treatment of the non controlling interest.
As shown on Slide 6, our pre tax operating margins were 29% 26% for the 4th quarter and 5 month 2018 successor period respectively or 30% 35% on an adjusted basis. Adjusted EBITDAX as we show Slide 10 was $193,000,000 for the 4th quarter and approximately $328,000,000 for the period we own the assets in 2018. Looking at our cash flows for the 5 month 2018 successor period and as shown on the waterfall chart on Slide 11, started with approximately $116,000,000 of cash immediately after closing the transaction with Enerbus last July. Our cash flow from operations after transaction costs paid at the close of the business combination and excluding changes in working capital were $331,000,000 during the period. Our cash capital outlays were $142,000,000 excluding capital accruals, and we spent $147,000,000 of cash on asset and property acquisitions.
During the period, we generated free cash flow in excess of our capital and acquisition spending and ended 2018 with $136,000,000 of cash on the balance sheet, an increase of approximately $100,000,000 compared to the end of Q3. We have an undrawn $550,000,000 credit facility and have ample liquidity allowing us to continue to execute on our strategy. Our long term debt at year end 2018 was approximately $389,000,000 and in line with our policy of maintaining conservative leverage. Our net debt stands at less than half a turn of our annualized EBITDAX and a summary balance sheet for year end 2018 as shown on Slide 12. Our total proved reserves at year end 2018 are approximately $100,000,000 BOE composed of roughly half oil and 71% liquids and compared to approximately $76,000,000 BOE at the end of 2017.
The year end 2017 reserve amount relates to 1 year development plan of the assets acquired in the transaction with Enerbeth. Proved undeveloped reserves at year end 'eighteen represent 24% of total proved reserves, the vast majority of which will be developed within 1 year. As Steve mentioned, we ended the year on a strong note exceeding our earlier production guidance while spending 57% of our adjusted EBITDAX on drilling and completing wells. Turning to guidance for 2019, we expect our Q1 total production to be equal to or better than 4th quarter levels. We estimate that our Q1 volumes to be impacted by the timing of new wells turned in mine in Karnes, lower non op activity and some downtime in Giddings due to pipeline maintenance.
Production is expected to accelerate in subsequent quarters due to new well completions in both Karnes and Giddings and higher planned non op activity. We first announced the transaction nearly a year ago, our expectations were that we would grow moderately adding about 6,000 MBOE per day each year or roughly 3,000 a day in each of the Karnes and Giddings assets. That outlook has not changed and we expect our production to exit 2019 approximately 6,000 barrels a day higher than what we achieved in the Q4 of 2018. As Steve noted, our capital spending as a percentage of EBITDAX is expected to run a little hotter in the Q1 than during recent periods, and this is partly due to the decline in oil prices. As we adjust our pace of activity to lower product prices, our capital levels are expected to trend lower as our current plan is to run 2 operated rigs into the Q2.
We also anticipate capital savings of approximately 5% specifically related to well completion materials and services. We continue to expect that our total capital for drilling and completions to be within 60% of our full year 2019 EBITDAX. Regarding our costs, the 4th quarter was our first full period owning the asset base and so we believe these per unit costs are reasonable proxy for 2019. We estimate that our 2019 DD and A rate should be approximately $20 per BOE. Our per unit cost for the Q4 5 month successor period is shown on Slide 6 of the presentation.
Product price changes at current prices affect our earnings before income taxes by roughly $12,000,000 on an annualized basis for every $1 per barrel change in oil prices and $3,000,000 on an annualized basis for a $0.10 per Mcf change in natural gas prices. We're now ready to take your questions.
We will now begin the question and answer session. The first question today comes from Neal Dingmann with SunTrust. Please go ahead.
Steve and Chris, my question first question is just you've given overall production guidance out there. How do you all think about just the Karnes production, particularly maybe the trajectory later this year after dropping to 1 rig and then how quickly that might change if you bring a rig back?
It's not going to make much effect because the indications from our partners in there is for a hotter drilling program than they had last year really. So if you were to look at their portfolios, I don't think about these companies or who they are, but if you look at their portfolios, the Karnes assets have quick paybacks and high returns and their shift is more challenging oil price environment, they're shifting there. So we would expect more 3rd party. And so we've cut back our operated to keep things in balance. Otherwise we produce more than that.
So I think what you'll see is that production will go up all year.
Okay. And then just lastly the potential for and I think you've talked about alluded to this in the past Steve, just the potential for M and A around Karnes given how pristine that acreage is?
There's lots of small properties around. People have to get used to they go home and they tell her whatever their spouse or whatever that the property is worth $500,000,000 when oil was going to $90,000,000 and now it's worth $200,000,000 and so it's hard to sell. So people just have to get used to it somewhat lower price. We're pretty disciplined. We don't feel pressured to do anything.
Really no reason to worry about it. But as we see opportunities, we'll continue to look for stuff and we have several of them under review currently. We'll just see how it goes. But we're not we don't need to do anything we're not worried about. I'm more worried about overpaying because we're too anxious than I am missing something.
No, you certainly all have done a good job. Thanks again, Steve.
Sure. Thank you.
The next question comes from Nellie Raymond with Thompson Rice. Please go ahead.
Good morning, guys. You all built an impressive $100,000,000 cash in 4Q and now have $136,000,000 on your balance sheet. What are the options you'll have with the cash? And also you've mentioned in the release that you are evaluating small asset deals with the business model? Are these all in Karnes?
Well, I mean, there's only 3 choices for a company for what to do with the cash. I suppose you just leave it there, but I guess that's the 4th one. But putting that aside, small bolt on acquisitions, We don't have any plans to do a large scale public deal or anything like that. Sometimes people hear about that, but that's just some broker trying to hype the process. So small bolt on acquisitions, debt reduction, not real likely in our case.
And finally, some dividend program. I think we're a little early to begin a dividend program. And so we probably won't be thinking about that maybe next year. But I think at this point, I think right now we're focused on see if we can find something to build out the business. It's likely to be in the Karnes area rather than the Giddings area.
We have a big footprint in Giddings. There may be some small leases and that sort of thing in Giddings to fill in. As we do this exploration or whatever you want to call it or program in getting we're going to find areas which look better than we think. And we'll sort of try to go in and lease some acreage in those areas when we find it. And so we'll be a little slow in telling you about the good areas.
So we lease up all we need. But I think you should view it as primarily a Karnes thing. But we also look for a similar business model. So if we were to find something with a similar business model, that is the 60% grow more than 10% with 60% of your cash flow and have reported earnings in our good sized margins, pretax margin, including acquisition costs. We would do that.
I don't see much of that, but that's sort of the plan. But right now, we're thinking fairly conservatively.
That's very helpful. That's all I have for today.
Thank you.
The next question comes from Tim Rezvan with Oppenheimer. Please go
ahead. Good morning folks. Thanks for taking my question. My first question, I noticed that the Giddings footprint looks like it's down about 21 1,000 acres from your prior presentation in January. Can you talk about what drove that and how we could maybe expect that to trend going forward?
It was actually it was about down about 20,000 net. I think it was just an acreage adjustment when they went through and looked at the purchase accounting. There wasn't any sale or anything. It was just an when they actually looked at what the seller sold us, they found some scattered acreage that didn't look like he owned it.
Okay. Okay. Just want to make sure it wasn't major expiry.
No. There's no plan. You shouldn't read anything into that. There's no particular reason to sell it. We're not smart enough about it yet to have a program where we're selling down.
We may never be smart enough. It's all held by production. So there's no reason to do that. You might lose some leases for lack of drilling activity or something, but not much.
Okay. That's helpful. And then I guess my follow-up question on CapEx. I understand that the business model is not designed to allow you to give the kind of CapEx guidance that maybe Wall Street wants, but you have to have a pretty good line of sight on 1Q. And obviously, you're signaling pretty hard that we can expect it to be above 60%.
Can you put any parameters or any more granularity on how 2019 CapEx could look based on what you've spoken about now with the rig count you have?
Yes. We don't you have to understand then Karnes, at least a third of the program is in the hands of other people, which is what gives us more lack of forecasting ability than even the standard oil company, which has no ability. So we're less than none. So I think if you use an EBITDA model using sort of $55 oil area and $2.80 for gas $17 $18 for NGLs and multiply by 0.6, it's close to that. We're not trying to be evasive.
It's just we don't know exactly. 1st quarter will be fairly hot, probably north of 80% burn. And the second quarter will be down around 60%, we would guess and then it would fall back into the mid 50s and we'll be okay by the end. But that's sort of a guess because we don't know what the 3rd parties are going to do. And so I think if you could take whatever model you have if you use those parameters and multiply by 0.6 and you probably wouldn't be off more than 5% or 10%.
The next question comes from Jeff Grampp with Northland Capital Markets. Please go ahead.
Good morning, guys. Good morning. Just sticking on the non op side, I know you guys don't have a ton of longer term insight there. But just, I guess as best as you guys can kind of comment today, you mentioned 2018 was kind of the equivalent of half of a rig net to you guys. Is 'nineteen, we understand it's up, but is it does it get up to kind of 1 full rig to you guys, 3 quarters of a rig or I guess just trying to
get it It's probably closer based on what we know today it's probably closer to 1.
Okay, got it. Perfect. And on the 6,000 kind of growth rate that you guys are looking at exit to exit, understanding it's still kind of weighted pretty evenly between Giddings and Karnes. Can you remind us, I think you maybe mentioned it in the prepared remarks, but what's kind of baked in there regarding if and when the operated rig in Karnes comes back after leaving here shortly?
It doesn't. We didn't bake that in.
Okay. So that's just the one 2 operated and the non op?
Yes. And the non op basically picking up the slack, if you will. And that's all organic. Those are organic numbers, not everything.
Got it. Perfect. And then if I can sneak one more in just on the acquisition side, you mentioned some small ones you're looking at. Is the expectation that you guys can primarily do that out of free cash flow generation or can you just talk about your comfort level with tapping the line of credit to do any
free cash. We might borrow for a month or 2 or something against the line until the cash comes in. But I don't like that. So
The next question comes from Irene Haas with Imperial Capital. Please go ahead.
I have a question on Giddings. That area has previous drilling and so ought to be quite a bit of historical data. And my question for you is, how much what kind of exploration or engineering parameters you're trying to nail down before you can get comfortable with the play? And can you give us a little color on why is the trend variable from what you have drove thus far?
Yes, sure. If you do it like you would in Karn say, you basically use the oil in place heat maps to sort of guide you. And that helps in Giddings. But there's also not just large fractures, but micro fractures that we can't see or we hadn't seen. And what happens to the well is you drill a well and while there was maybe a lot of the data shows a lot of oil in place, you don't know and you frac it, you don't really know what's going to happen with the micro fractures.
And so sometimes it helps you, sometimes it doesn't. And so we need to do more work to figure out what the fracture pattern is. And so we're doing more either micro fracture microseismic or seismic. So to look to see if we can figure that out to improve our predictability. It's very the wells are good and but we're found we're just unable to predict exactly what's not forget exactly more or less what's going to happen even sometimes we think they're going to be oil wells or gas wells and vice versa.
So something we don't understand, we think it's a fracture pattern. So I think that's if you remember back years ago, people drilled on the fractures and forgot the fracture production without fracking. And so the fractures are a way to drain a bigger area. So the wells tend to come on with making something odd and improve over the 1st 6 months. So unlike a well in Karnes where you can pretty much tell how good a well it is in the 1st couple of months, probably take you 6 months because the fractures clean up, the water comes out and the well builds.
So we're just trying to figure that out. And we're also looking possibly to acquire some acreage. And so there's not a lot of reason to provide a lot of detail as to what areas are good and what our areas are not.
Got you. In your opinion, you have sort of views of your competitors, are they pretty much in the same boat nearby in the same neighborhood?
There's not really much in the neighborhood. There's your WildHorse assets and that's to the north of us and the wells are really quite different. And geo southern in the south it looks like some kind of variability down there and some of the smaller producers a fair amount of variability. You do need what we can tell you is that you need to apply science to drill wells. I mean if you just drill the wells randomly, you're probably not going to do real well.
Great. Thank you.
So sometimes what you see is the guys drilling randomly and they have bad results, it's because they didn't do anything, they just drilled the well.
Okay. Thanks. Thanks.
The next question comes from Brian Downey with Citi. Please go ahead.
Good morning. Thanks for taking the question. We appreciate the color on the production cadence over the next few quarters as you accelerate volumes into mid year. If you have any sense on how that translates on oil cut trajectory over those periods? I know you had mentioned roughly 3 MBOE a day each from Karnes and Giddings exit to exit, but I wasn't sure how that translated, if there are any timing expectations in between?
We're looking 52% to 54% black oil. Okay. For your average estimate? Yes. The problem really is that, let's say in Karnes, if you when somebody fracs a well near you, you shut your well down so you don't get hit by frac.
And then you bring your well back up again when they stop. And so you have this start and stop in it and you don't really they tend to come out a little gassier initially in that sort of process. So remember the numbers are fairly small. So there's no real averaging out of thing. So you wind up with what looks like more variability than actually exists.
Got it. Okay. Appreciate that. And then on the Karnes bolt on net acreage, I was wondering if you could comment how much of that was increased working interest on existing acreage versus adding adjacent. I noticed the map really didn't change all that much, but maybe I'm reading too much into that.
You're reading too much into it. We run a low G and A outfit. So we don't have professional map makers.
Got it. Appreciate that. Thanks guys.
The next question comes from Biju Perushanel with Susquehanna. Please go ahead.
Hi, good morning. Just wondering, the one rig that you will be operating and getting, can you give us a sense of how much of that will be all delineation versus are they going to be any portion of the drilling this year that will be, call it, development around some of the areas you've already delineated?
Yes, it's just some development. I'm guessing the third half to development depending on how things are going. We have the flexibility to if we get good results, maybe there'd be more exploration for one of them better work. And if it was also a little weaker, we will go to the sure things.
Got it. And then when you look sort of look at the Austin Chalk and the Karnes area versus the Giddings, can you talk about the key differences there? And if you've been I know it's a smaller footprint, you have had consistent results in the Conn's area. So what are some of the key differences that we're looking at?
Yes. One of the key differences is these fractures and the fact that the chalk was drilled heavily during the '70s 80s. And so there are wells in it that drain some of the oil. So if you want to think of it, it's some of it's been what was already produced when I was a kid. But you shouldn't overstate the Austin Chalk in Karnes or understated.
It's good, but it is variable through the area. And so there are some good areas and less good areas. So I think you just it's not a blanket that covers the entire county.
The next question comes from Jeffrey Campbell with Tuohy Brothers.
I wanted to just ask again, go back to the acquisitions. I found it pretty impressive you guys have been able to keep pulling off these bolt ons in such a mature area. I was wondering if the fact that you're paying cash for acquisitions is proving to be a competitive advantage and also are there any other advantages that Magnolia is bringing to these deals?
I think there's 3. Some people want the stock because they overspent to acquire the whatever we may offer less than they paid for it. And so this gives them some upside and we have this I apologize for the confusion it costs, but these Up C structure, the non control shares or whatever we're calling them, the Class B shares, they're identical in all ways with the other shares except the tax is deferred for the person who takes them rather than having to pay tax right away. So if somebody has a low tax basis or maybe they have a promoter or something like that that they would have to pay ordinary income under the new tax law. It can be put in the structure.
So that's an advantage. The other the main advantage is, we drilled so many wells, we've been in so many wells, we really understand it a lot better than the average. The risk you always run-in an area like this is a new entrant comes and he doesn't understand what he's doing and he decides to pay a new entrant premium. Usually that's a road to hell. But I think we've got a lot of understanding.
And again, our G and A will be spread and G and A and even field costs will be spread over what we acquire because as long as you're within a short truck driving business, we can spread our field hands up. So I think there's some real field synergies in the operating costs. There's knowledge and flexibility to pay either cash or stock depending on the tax needs of the party.
Okay, great. Thanks for that color. That Beecher angle is really quite interesting. I just my other question was that before the '14 Q4 'eighteen price drop, I believe you were forecasting that Karnes was going to spend well below its EBITDA and generate free cash while Giddings might spend up close to its self generated EBITDAX. So I was just wondering, is that still the plan or is Giddings spend down back
a little bit? That's still the plan.
Okay. Okay, great.
Thank you. We've cut back Giddings. I think I've told this, this is like portfolio manager. You tell him you got $10,000,000,000 you got $1,000,000,000 ideas. You tell him he's got $10,000,000 he gives you his best ideas.
So keeping the guys on a diet is a good management technique.
Okay, great. Thank you.
The next question comes from Michael McAllister with MUFG. Please go ahead.
Thank you for taking my question. It seems that the Giddings program actually is doing a little bit better because you have a comfortability to take a rig out of the program for 2019 at this juncture and you're keeping the same kind of production forecast that you gave earlier?
Yes, it's doing it's certainly better than we told you it was going to do. So maybe so but we wanted to be conservative in the beginning. There'll be some drilling on Giddings, which will move the rig around a little. And the lumpiness is caused by the completion crews because we've got to get enough completions for send a completion crew in there. So it might be a little lumpy from quarter to quarter.
That's just basically caused by when you decide to complete the wells.
And what would be the signal to add a second rig to that program?
When we can accomplish it with the cash flow numbers? Well, if you build That's true. Yes. And the acreage isn't going away. And if we manage our all, if I want a better word, exploration program well, we'll have lots of locations as the cash flow in the business improves.
So I'm not really worried about that. You really have to keep if you wander off your discipline, you can sort of ruin a good thing with your own enthusiasm. So you try to get people to focus on what's real good now and let next year take care of itself. If you don't have any gun to your head like continuous drilling obligations and stuff.
Okay. Is there, I guess, a cash level on either end, low end or the high end where have your own boundaries as a
Well, I mean, we I don't like that. I think that's bad for commodity businesses.
So
we would borrow for an acquisition for on a short term basis. I mean short meaning under a year. But that's about all. So I think I don't have any problem if we can do a good job in finding acquisitions, spending the 40% as long as it's building value. But if it's not building value or we're just wasting money, I assume give it back, my wife can spend it.
You would be willing to build up to 2 $50,000,000 $300,000,000 if there was nothing out there that made sense to the
I doubt that. It's simply if we don't have a forward look that says that the money will be consumed in a reasonable period of time like a year, we'll figure out something else to do with it. And again, there's only 2 other choice. You take dividend, buying stock, I mean, that's the choice and there's really not enough liquidity to buy in stock right now.
It's true. Would you be able what would you tolerate on the low end as a for like the length of time?
If we had no cash and we're in and out of the line that'd be all right too.
Okay.
That's all I had. Thank you.
Thanks.
This concludes our question and answer session and also concludes our conference.