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Good morning, and welcome to the Magnolia Oil & Gas Corporation's Fourth Quarter 2018 Earnings Conference Call. [Operator Instructions]. Please note, this event is being recorded.
I would now like to turn the conference over to Brian Corales, Vice President, Investor Relations. Please go ahead.
Thank you, Anita, and good morning, everyone. Welcome to Magnolia Oil & Gas' Fourth Quarter 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 risk 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 fourth quarter 2018 earnings press release as well as the conference call slides from the Investors section of the company's website at www.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 in some of the details, the 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 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 an 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 six months since closing the transaction of EnerVest last July, we have exceeded most of our original business plan objectives during 2018. Our fourth quarter 2018 production averaged nearly 62,000 BOE a day, and the rate was more than 30% higher than our original full year guidance. Our higher than forecast production growth is due to stronger than expected well performance, drilling efficiency gains and higher nonoperated activity. We emphasized that much of this was accomplished by averaging roughly 2.5 rigs and utilizing one 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 transactions 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 strengthened our core operations in both Karnes and Giddings. Most notably, during the third quarter of 2018, we acquired substantially all of the South Texas assets of Harvest Oil & Gas Corporation, which added both production and drilling inventory to our Karnes County and Giddings assets. Additionally, in the fourth quarter, we added to our Karnes position acquiring approximately 1,850 net acres.
Generating high pretax margins is another characteristic of our business model. Our EBIT margin for 26% during the period we owned the assets in 2018, including 29% in the fourth quarter or 35% on an adjusted basis for the five month period. We accomplished these objectives while maintaining low financial leverage and strong liquidity, including a $550 million undrawn credit facility and a cash balance that grew by approximately $100 million during the fourth quarter.
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, and we view this environment as one in which we can thrive. While we have been running two rigs in Karnes for most of the first quarter, we plan to release one 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 nonop activity, our capital at percent of EBITDAX is expected to run a little hotter than normal during the first quarter. 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 double - 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 continued to see high-quality well results, which remained fairly constant and steady and with a predictable outcome. We see ample opportunities here where small to midsized bolt-on acquisitions to further strengthen our position over time.
In Giddings, while we increase the our productions related to the quality of the wells drilled, the results continued to be quite variable. Our current plan is to run one rig at Giddings and continue to drill some appraisal wells to help improve our understanding and further delineate our sizable additions where we have approximately 650,000 in gross acres. Our Giddings acreage is almost entirely held by production.
Finally, we're continuing to build up Magnolia's 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, and we're pleased of the performance of our assets and what we've accomplished so far. We remain very optimistic regarding our prospect of opportunities in 2019, which 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 fourth quarter ending 2018 was the first full quarterly period under which we own the assets since we disclosed - since we closed the transaction with EnerVest at the end of last July.
Second, we'll refer to the five 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 for our natural gas and NGL production volumes and has also contributed to the slightly lower percentage of oil in our production mix. Our reported production volumes for the five month successor period of ownership reflect this adjustment for the adoption of the new standard. My expectation is that our financial statement disclosures 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 would - that's posted on our website. We reported GAAP net income attributable to Class A common stock of $33 million or $0.21 per diluted share for the fourth quarter of 2018. Total reported net income for the period, which includes the noncontrolling interest, was approximately $58 million 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 the EPS when comparing us to other similar companies.
Turning to Slide 7. Our total production averaged 61,000 - 61.9 Mboe per day, during the fourth quarter, an increase of more than 5% sequentially and ahead of our previous guidance. Fourth quarter production at Giddings Field was 20.6 Mboe per day or sequential increase of nearly 22%. The higher-than-expected production at Giddings for the fourth quarter was 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, and we remain very optimistic about our prospect of opportunities in the field.
Our revenues totaled $255 million in the fourth quarter, benefiting from both higher production 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 fourth quarter, our realized prices remained relatively strong as we were 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 fourth quarter.
Turning to costs, our LOE during the fourth quarter was $3.46 per BOE and higher than the third quarter 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 fourth quarter DD&A was $19.65 per BOE, and reflects Magnolia's plan to focus on near-term development of PUD reserves.
Fourth quarter G&A expenses were up $18.5 million or $3.25 per BOE. These costs increased sequentially as we continued 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&A cost in 2019 should be similar to fourth quarter levels.
Our total reported net income for the fourth quarter included $2.2 million 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 fourth quarter, and we expect the 2019 rate to be in the range of approximately 12% to 15%, due to the accounting treatment of the noncontrolling interest. As shown on Slide 6, our pretax operating margins were 29% and 26% for the fourth quarter and five month 2018 successor period respectively or 30% and 35% on an adjusted basis.
Adjusted EBITDAX as we show on Slide 10 was $193 million for the fourth quarter and approximately $328 million 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, we started with approximately $116 million of cash immediately after closing the transaction with EnerVest 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 million during the period. Our cash capital outlays were $142 million, excluding capital accruals, and we spent $147 million of cash on asset and property acquisitions. During the period, we generated free cash flow in excess of our capital on acquisition spending and ended 2018 with $136 million of cash on the balance sheet, an increase of approximately $100 million compared to the end of third quarter.
We have an undrawn $550 million 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 million and in line with our policy of maintaining conservative leverage. Our net debt stands at less than 0.5 turn of our annualized EBITDAX and a summary balance sheet for year-end 2018 is shown on Slide 12. Our total proved reserves at year-end 2018 were approximately 100 million BOE composed of roughly 1/2 oil and 71% liquids and compared to approximately 76 million 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 EnerVest. Proved undeveloped reserves at year end '18 represent 24% of total proved reserves, the vast majority of which will be developed within one 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 first quarter total production to be equal to or better than fourth quarter levels. We estimate that our first quarter volumes to be impacted by the timing of new wells turned in line in Karnes, lower nonop 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 nonop activity. When 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 that we expect our production to exit 2019 approximately 6,000 barrels a day higher than what we achieved in the fourth quarter of 2018.
As Steve noted, our capital spending as a percentage of EBITDAX is expected to run a little hotter than the first quarter than during recent periods and this is partly due to the declining 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 two operated rigs into the second quarter.
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 cost, the fourth quarter was our first full period owning the asset base, and so we believe these per unit costs are a reasonable proxy for 2019. We estimate that our 2019 DD&A rate should be approximately $20 per BOE. Our per unit cost for the fourth quarter and five 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 million on an annualized basis for every $1 per barrel change in oil prices and $3 million on an annualized basis or a $0.10 per MCF change in natural gas prices.
We're now ready to take your questions.
[Operator Instructions]. The first question today comes from Neal Dingmann with SunTrust.
Steven and Chris, my question - first question is just, I know 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 the one rig and then how quickly that might change if you bring the rig back?
It's not going to make much effect because the indications from our partners in the - in there is for a hotter drilling program than they had last year really. So if you - even if you were to look at their portfolio, I don't know anything about these companies, who they are, but if you look at their portfolios, the Karnes assets have quick paybacks and high returns and they're shift in - more challenging well price environment, they're shifting their. So we would expect more third party. And so we've cut back our operated just to keep things in balance, otherwise we produce more than that. So I think what you'll see is that the - 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&A around Karnes, given how pristine in that acreage is?
There's a lot of small properties around people have to get used to of. They go home and they tell their - whatever, their spouse or whatever that the properties worth $500 million when and oil is going to $90 and now it's worth $200 million and so it's hard to sell. So people just have to get used to somewhat lower price. We're pretty disciplined, we don't feel pressured to do anything, there is no - 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 that I am missing something.
The next question comes from Lenny Raymond with Johnson Rice.
[Indiscernible] impressive $100 million of cash in 4Q and now have $136 million in the balance sheet, what are the options you'll have with the cash? And also you have mentioned in the release that you all are evaluating small asset deals to fit the business model, are these all in Karnes?
While I mean there's only three choices for a company for what to do with the cash. I suppose you should leave it there, but I guess that's floor plan. But putting that aside, these 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 really likely in our case. And finally, some sort of dividend program, I think we're a little early to be in a dividend program and so I - we probably won't be thinking about that, so maybe next year. But I think at this point, I think right now we're focused on to 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 Giddings, 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 until we lease up all we need. But I think that you should view it as primarily a Karnes thing. But we also look for a similar business model, so if were to find something, it was a similar business model, that is the 60% - grow more than 10% with 60% of your cash flow and have reported earnings and good sized margins, pretax margins, including acquisition cost. We would do that, I would see much of that, but that's sort of the plan. But right now we're thinking fairly conservatively.
The next question comes from Tim Rezvan with Oppenheimer.
My first question, I noticed that the Giddings footprint looks like it's down about 21,000 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, that - I think was just an acreage adjustment when they went through the purchase accounting. There wasn't any sale or anything, it was just - when they actually looked it what the seller sold us, they found some scattered acreage that didn't look like he owned it.
Okay, okay. Just wanted to make sure it wasn't major exploration.
There is no plan, the - 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. May never be smart enough. It's all held by production, so there is no reason to do that, you might lose some leases for lack of drilling activity or something but not much.
Okay, 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 your signaling pretty hard that it - 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 just spoken about now with the rig count you have?
Yes. We don't - you have to understand that in Karnes at least the 1/3 of the program is in the hands of other people, which is what gives us more lack of forecasting abilities and 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, the 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 that we don't know exactly. The first quarter will be fairly hot, probably - yes, north of 80% burn, and of the second quarter it'll be down around 60%, we would guess and then it 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 third 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 then you probably wouldn't be off more than 5% or 10%.
The next question comes from Jeff Grampp with Northland Capital Markets.
Sticking on the nonop 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 comment today, you mentioned 2018 was kind of the equivalent to half of a rig net to you guys, is '19 - we understand it's up but is it - does it get up to one full rig to you guys, three quarters of a rig or I guess just trying to get a sense...
It's probably closer - based on what we know today, it's probably closer to one.
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 may be mentioned in the prepared remarks, but what's kind of baked in there regarding if and when the operated rig in Karnes come back after leaving here shortly?
It doesn't. We didn't bake that in.
Okay, so that's - so there's the one - two operated and the nonoperated?
Yes, and the nonop basically picking up the slack, if you will. And that's all organic, that those are organic numbers not everything.
Got it . Perfect. And if I can just sneak on one more just on the acquisition side, you mentioned some small one's 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 acquisitions that you might see here?
I think it's very likely to be done within either cash of the balance sheet or free cash. We might borrow for a month or two 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.
I have a question on Giddings. That area has previous drilling and so it's 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 drilled thus far?
Yes, sure. If you do it like you would in Karnes say, you basically use the oil in place heat maps to sort of guide you and that helps in Giddings. But there is there's also not just large fractures but micro fractures that we can't see or we hadn't seen them, and what happens to the well is you drill a well and while there was - maybe a lot - the data shows a lot of oil in place, you don't - 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 to look and see if we can figure that out to improve our - the predictability. It's very - the wells are good and - but we 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 the fracture pattern. So I think that's - if you remember, back years ago, people drilled on the get fractures and got the fracture production without fracking. 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 first six months, so unlike a well in Karnes where you can pretty much tell how good a well it is in the first couple of months, probably take you six 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 areas are not.
Got you. In your opinion, you have - the sort of views on your competitors are they pretty much in the same boat nearby in the same neighborhood?
There's not really much in the neighborhood. The - there is old WildHorse assets and that's to the north of us and the wells are really quite different, and GeoSouthern in the south looks like some kind of variability down there and some of the smaller producers of have 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. 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 drill the well.
The next question comes from Brian Downey with Citi.
We appreciate the color on the production cadence of over the next few quarters as you accelerate the volumes into midyear, but do you have any sense on how that translates on oil cut trajectory over those periods? I know you had mentioned roughly 3 Mboe each from Karnes and Giddings, exit to exit but I wasn't sure how that translated if there are any timing expectations in between?
No, we're looking 52% to 54% black oil.
Okay. Sort of up. So your average is...
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 a frac, and then you bring your well back up again when they stop, and so you have to start and stop in it, and you don't really - it tend come out a little gas here initially in that sort of process. So remember, the numbers are fairly small that were - so there's no real averaging out of this thing. So you wind up with what looks like more variability than actually exists.
Got it. 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. Yes, our - we went a little low [indiscernible] so we don't have professional mapmakers.
Your next question comes from Biju Perincheril with Susquehanna.
Just wondering, the one rig that you will be operating in Giddings, can you give us a sense 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?
So some development. I'm guessing the third to half in development depending on how things are going. We have some flexibility to the - if we get good results maybe there'll be more exploration from one of our [indiscernible]. And if the results are a little weaker, we'll 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 - even though it's a smaller footprint, you've had consistent results in the Karnes area, so what are some of the key differences that we should be looking at?
One of the key differences is these fractures and the fact that the Chalk was drilled heavily during the '70s and '80s, and so there are wells in it that drained some of the oil. So if you want to think of it, it's - some of it's been - was already produced when I was a kid. So - and that - but you shouldn't overstate the Austin Chalk in Karnes are 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 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 - go back to the acquisitions side. I found it pretty impressive you guys been able to keep pulling off these bolt-ons in such a material 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's bringing to these deals?
I think there's three. 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 upside, and we had this, I apologize for the confusion it caused but these off-sea structure, the noncontrolled 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 before the person who takes them rather having to pay tax right away. So somebody has a low tax basis or maybe they have a promoter or something like that, that 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 they're a lot better than the average. The risk you always run in an area like this is, the new entrant comes, 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 lot of understanding. And again, our G&A will be spread, and G&A and even field cost is spread over what we acquired because as long as you're within a short truck driving distance, we can spread our field hands up. So I think there's some real field synergies in the operating cost, there's knowledge and flexibility to pay the either cash or stock depending on the tax needs of the party.
My other question was that before the 14, the fourth quarter '18 price drop, I believe you were forecasting that Karnes was going to spend well below its EBITDA and generate free cash flow class, Giddings might spend up close to its self-generated EBITDAX. So I was just wondering, is that still the plan or is Giddings spend docking back a little bit.
That's still the plan. We've [indiscernible] back - we've [indiscernible] back Giddings. I think I've told this, this is like a portfolio manager, you tell them you've got $10 billion, you've got a 1 billion ideas, you tell him he's $10 million, he gives you his best ideas, so keeping the guys on a diet is a good management technique.
[Operator Instructions]. The next question comes from Michael McAllister with MUFG.
It seems that the Giddings program actually is doing a little bit better because you have the 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 still - it's certainly better than we told you it was going to do. So - but we wanted to be conservative in the beginning. There'll be some drilling on Giddings, we'll move the rig around a little. And the lumpiness is caused the completion crews because we got to get enough completions for sending the completion crew in there, so you might be a little lumpy from quarter-to-quarter that's because it's frankly 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 could accomplish it with the cash flow numbers. So the acreage...
Well, if you built...
Yes, and the acreage isn't going away, and if we manage our, call it, from - on our better oil 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 you discipline, you could 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's next year take care of itself, if you don't have any gun, your head life continuous drilling obligations and stuff.
Okay. Is there, I guess, a cash level on either end, low end or the high end, where you have your own boundaries? Is that a...
I mean, we - I don't like that because I think that's bad for commodity businesses. So I - we would borrow an acquisition for - on the short-term basis, I mean, short being under a year, but that's about all. So I think I don't have any problem if I - we can do a good job and 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 just assume give it back my wife can spend it so...
You would be willing to build up to $250 million, $300 million 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 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 two other choices on the - either by dividend and buying stock, I mean that's the choice and there's really not enough liquidity to buy in stock right now.
True. Would you be able - what would you tolerate on the low end as a - for like a length of time?
If we had no cash and we're in and out of the line that would be all right too..
This concludes our question-and-answer session, and also concludes our conference. Thank you for attending today's presentation. You may now disconnect.