Magnolia Oil & Gas Corp (MGY) 2019 Q4 法說會逐字稿

Good morning and welcome to the Magnolia Oil Fourth Quarter and Full Year 2019 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 of Investor Relations. Please go ahead.

Thank you, Andrew, and good morning, everyone. Welcome to Magnolia Oil & Gas' Fourth Quarter and Full Year 2019 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 annual report on Form 10-K 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 download Magnolia's fourth quarter and full year 2019 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.

Thank you. Good morning, and thank you for joining us today. I will provide a summary of some of our achievements in 2019, our outlook and plan for 2020 as well as an update on our Giddings asset. Chris will review some of the details of the financials and provide some additional guidance for the year before we take your questions.

We had many accomplishments as an organization during 2019, our first full calendar year as a public company, we've been in business for 18 months. And despite the continued challenging environment for the energy sector, the quality of our assets and the characteristics of our business model has served us well and continues to provide us with a strong foundation. Our strategy of focusing on generating free cash flow, combined with low levels of debt, supported our strong performance last year and positioned us well for this year.

During 2019, we invested 60% of our cash flow to our drilling and completing wells and unrelated production equipment, collectively, the D&C capital. This is in line with our original objective and continues as part of our ongoing strategy. As a small company, part of our plan is also to generate moderate growth, and we were able to grow our production volumes by 10% in the fourth quarter of 2019 compared to the year-ago period. The free cash flow generated by the business provide us with options to allocate capital towards opportunities that are most accretive to the value of our stock. Our remaining free cash flow during 2019 was used to successfully complete multiple small oil and gas property acquisitions, further strengthening our overall asset base.

These acquisitions would include producing properties, expand our acreage position in our core Karnes area by 30% and more than replaced our inventory of wells drilled during 2019. We also allocated $79 million towards a repurchase of 7 million Magnolia shares. Importantly, 6 million of the shares we repurchased were Class B common shares, which are not included in the public float and are essentially the same as the Class A stock in terms of voting rights and economic value. Including outlays for our capital program, the acquisitions and share repurchase, we ended 2019 with $47 million more cash on hand compared to the prior year.

One of our more important accomplishments over the last year was significant progress made towards further derisking, understanding our Giddings Field asset, our appraisal and exploration program using our current multi-variant model, along with associated science improved our ability to predict better target areas to drill at Giddings. We are beginning to see the results of our program to show up in our production mix. Two wells we brought online at Giddings in the later half -- later part of the third quarter produced approximately 1,700 barrels a day during their first 30 days online and have averaged more than 1,500 barrels a day during the first 120 days. During the fourth quarter, we added 2 wells at a combined rate of more than 1,100 barrels a day during their first 60 days. These wells are about 15 miles apart are in -- and are in new areas. These are essentially exploration wells. These recent new wells pushed up our fourth quarter oil production in Giddings by 24% sequentially.

We plan to allocate incremental capital towards Giddings this year, and given our improved understanding and increased confidence in the field, this additional activity will represent an early-stage development program for later this year, which will supplement our ongoing appraisal efforts. The initial plan should allow us to lower our overall well cost and capture some efficiencies that would be realized more broadly once we move to a larger scale development in the field.

We continue to evaluate several small and midsized bolt-on oil and gas property acquisition opportunities. While we were optimistic around the prospect for more bolt-on deals entering this year, the recent weakness and volatility in product prices has frozen the process. Maybe it will thaw out a little today. In addition, the recent weakness in our share price has raised our cost of capital, lowered the amount we're willing to pay on our transaction. While we expect product prices to stabilize, we'll continue to be disciplined around our approach to M&A, keeping in mind that our objective around any transaction is to make the company better.

Our strategy and business model for this year remains unchanged. Our D&C capital spending, expected to be approximately 60% of our cash flow, providing us with free cash flow while continuing to maintain low levels of debt. We anticipate some of drilling -- we anticipate shifting some of our operated capital towards Giddings as our non-operated activity in Karnes is expected to be 15% to 20% higher than last year. If product prices remain weak, we have the flexibility to adjust our spending on our operated activity to accommodate our model as our operated locations in Karnes are not going away. Our free cash flow provides us opportunity to allocate capital towards opportunities that are most beneficial to our shareholders.

I'd like to talk a little about our business plan, which hasn't really changed. Like we -- like I said earlier, we intend to spend 60% plus or minus 5% of our EBITDA on drilling and completing wells and associated production equipment. After interest expense, our remaining funds are for acquisitions, share repurchases and at some point, dividends. This drilling program should be enough to grow production, a total of 6,000 BOE a day, over the 2 operating areas.

As far as acquisitions, we continue to have no large-scale or public M&A. We expect some bolt-on acquisitions, most likely in the Karnes area. Significant number of Karnes areas opportunities exist, which will be available over the next couple of years. Right now, it's hard to come up with a value for either the buyer or the seller. And our debt, of course, will continue to be minimal.

A little discussion about the difference between Karnes and Giddings. The Eagle Ford, Austin Chalk and Karnes is well known. The wells drill quickly. They have high oil cut. The wells have peak production in the first 30 days and decline sharply over the next few months. As a result, they have high internal rates of return that has a quick payback. All of our acreage is held by production. The best time to drill is when oil prices are high because most of the production is obtained in a short period of time. So if oil is $50, that's approximately what you're going to get for it because the payback is so quick.

In Giddings, which we drill in the Austin Chalk, there's 2 sources of production in the chalk, one from the natural fractures and one to resolve the fracking process. This leads to a larger drainage area than what we expected from just the fracking process. As a result, the wells initially produce a lot of water, both formation and frac fluid for both sets of fractures. Peak production is generally around 90 days after completion, but the decline rate is much less than a Karnes well. Payout is somewhat longer, but the total amount of hydrocarbons produced over the life of the well is significantly larger than a Karnes well.

Giddings wells are most appropriate if one expects future oil price to be better than current ones. One of our objectives with the appraisal process to reduce the overall costs. In 2020, we expect to reduce the per-well Giddings cost by about 20%. Virtually all of our acreage there is held by production. We believe we have several large contiguous areas that are likely to work well, one of which is about 70,000 acres, it's about 100 sections. With 4 wells per section that implies 400 locations in this 1 area, more than 10 years of inventory with 2 years -- 2 rigs running. We have just completed a 2-well pad in this area. It appears that both wells are each capable of producing 1,000 barrels of oil a day, plus around 3 million cubic feet of gas a day.

In the current situation, the nonoperated activities in Karnes is picking up. We are currently operating 1 well in Karnes and effectively, through nonoperated activity, have another 2/3 to a full net rig. We are not -- we're also not abandoning Karnes but allocating more capital to Giddings this year to enhance our development as the Karnes location is not going anywhere.

By shifting our operating rig to Giddings over a short period of time, we expect Giddings production to overtake Karnes on a BOE basis and a little longer period overtake Karnes on a barrel-of-oil basis. With increased production at Giddings, we can start building a base of lower decline production in a more efficient manner, ultimately reducing the amount of cash flow needed to keep production flat. The price for this is lower volume growth this year as the Giddings wells come on slower than Karnes wells, but also have a much shallower production profile.

Like to turn the call over to Chris.

Thanks, Steve, and good morning, everyone. I plan to review some of the highlights from the fourth quarter and full year 29 (sic) [2019] results and provide some additional guidance for 2020 before turning it over to you for questions.

Looking at Slide 4 of the presentation that's posted on our website. We reported total net income for fourth quarter 2019 of $13.6 million or $0.05 per diluted share and $85 million or $0.28 per diluted share for the full year. Fourth quarter adjusted EBITDAX was $171 million with 42% spent on drilling completions and related production equipment or D&C capital, which was lower or better than our earlier outlook.

For full year 2019, we spent 60% of our adjusted EBITDAX on D&C capital, which is consistent with our business model. As product prices declined, we stayed disciplined around our spending, reducing our D&C capital to 45% of our adjusted EBITDAX during the second half of 2019. Total production for the company averaged 68,300 BOE per day during the fourth quarter, a 10% increase compared to last year and with oil production representing 52% of our total volumes. We increased our net acreage position in the Karnes area by more than 30% during 2019, adding nearly 5,200 net acres through bolt-on acquisitions.

As shown on Slide 5, our cash flow from operations before changes in working capital for the fourth quarter of 2019 was $163 million. Our total D&C cash outlays for oil-and-gas properties was $70 million during the period or approximately 43% of our cash flow from operations before changes in working capital. Like every quarter since the company's inception, we generated free cash flow during the fourth quarter, generating $93 million of free cash after capital during the period. We repurchased 6 million Class B common shares of Magnolia stock in the fourth quarter for $69 million, ending the quarter and the year with $183 million of cash on the balance sheet.

Slide 6 shows a summary of the company's total share count since Magnolia's inception, including the breakdown between Class A and B common shares. We repurchased a total of 7 million shares, including 6 million Class B and 1 million Class A shares through the -- through year-end 2019. The shares we -- the shares repurchased have roughly offset the 7.3 million shares we've issued for acquisitions. We also completed the exchange for all our outstanding public warrants, which added 9.2 million Class A shares to the public float and simplified our capital structure.

As Steve mentioned, both the Class A and Class B common shares are essentially identical in terms of their voting rights and economic value. However, since the Class B shares are not publicly traded, the repurchase of these shares did not diminish the public float. There was a total of 253.1 million shares outstanding at the end of 2019.

Our long-term debt remained unchanged, ending the year at approximately $390 million, and our net debt as a percent of total equity is approximately 8%, as part of our ongoing policy maintaining low leverage, summary balance sheet as of December 31, 2019, as shown on Slide 7.

If you look at Slide 8, our total fourth quarter 2019 cash operating cost including G&A was $9.80 per BOE, a 10% decrease from the prior year period. We expect our per-unit cash operating cost including G&A to be similar in 2020.

I do want to highlight the improvement in our drilling, completion and capital efficiencies at Karnes during 2019. Our drilling days have declined about 15% from 2018 and pumping hours per day have increased 10% compared to last year. These improvements resulted in a 13% year-over-year decline in the cost per stimulated foot. In Giddings, we are expecting total well cost to decline about 20% compared to last year's levels as we move towards development drilling later in the year.

As shown on Slide 9, our proved developed reserves -- reserve additions during 2019 were 35 million barrels of oil equivalent, an increase of 13% compared to prior year levels and we replaced 142% of last year's production. Our total D&C capital and property acquisition costs last year were $523 million providing a proved developed F&D cost of around $15 per BOE. This F&D cost is representative of our full cycle cost of development and should be closer to the DD&A rate that runs through our income statement over time. We limit our PUD bookings to a 1-year development plan for the wells we expect to drill and complete this year.

Turning to guidance for 2020. We expect to spend approximately 60% of our adjusted EBITDAX for D&C Capital. This core characteristic of our business model remains unchanged. While our current plan anticipates drilling and completing a similar number of wells in 2020 as compared to last year, improved efficiencies of our drilling program, combined with lower oilfield service costs, should reduce our overall well cost by about 10% compared to last year. We estimate that this year's capital activity program would result in total year-over-year growth of approximately 5%, including growth in Giddings oil production of more than 20%.

Based on the pace of our capital spending and estimated non-operated activity, we expect the shape or pattern of this year's quarterly production profile to be comparable to 2019 with higher spending and activity levels seen in the earlier part of the year followed by increased production during the second and third quarters.

As Steve mentioned, based on our increased confidence and strong results in Giddings, we plan to move our operated rig in Karnes to the Giddings field later this year to begin an early-stage development program. The additional Giddings activity is expected to be evident in our production volumes through this year. We also expect to lower our overall well cost in Giddings and capture additional efficiencies through our experience that would be recognized more broadly through a larger scale development of the field over time.

First quarter D&C capital is expected to be around 85% of our adjusted EBITDAX at current product prices and our heaviest level of spending during the year. We currently estimate that our non-operated capital and activity in Karnes to increase by 15% to 20% versus 2019 levels. Despite this higher rate of capital, we expect to generate free cash flow in the current quarter and throughout the year as our spending gradually declines.

As noted in the press release, we estimate our total production in the first quarter to be around 65,000 BOE per day as most of the wells turned in line are expected to occur in the latter part of the quarter. Oil production is expected to be approximately 52% of our total volumes for the period. If we're faced with a continued weak product price environment, we have the flexibility to adjust our activity levels to keep our spending around 60% of our adjusted EBITDAX.

To wrap up, I'd point you to Slide 10, summarizing our cash flows for 2019, where we generated $658 million of cash flow from operations before changes in working capital. Our cash outlays included D&C capital for organic drilling program of $435 million, $86 million of cash for acquiring small bolt-on oil and gas properties and $79 million towards the repurchase of Magnolia common stock. We had $47 million more cash on the balance sheet at the end of 2019 and -- than at the start of the year, and we did not incur any additional debt. Like last year, we expect to generate free cash flow every quarter in 2020. Our D&C capital is expected to be approximately 60% of our adjusted EBITDAX, and we plan to shift some of our development spending to Giddings from Karnes later in the year.

Although the M&A environment remains volatile, as Steve mentioned, our continued focus is to generate free cash flow, providing us with options to further enhance our business and the value of our stock. We're now ready to take your questions.

(Operator Instructions) The first question comes from Neal Dingmann of SunTrust.

My first question is on Giddings. You all mentioned moving the second rig to Giddings to focus on development activity in the play. And I'm just wondering, in your prepared remarks, you gave some detail on a few sections. I'm just wondering, could you provide further details, you and Chris, on what gives you the increased confidence to begin that development process there?

Well, it's pretty straightforward. We have a model for locating the wells. The model is delivering actually better results than the model predicted. So we have a certain part of it, which we have a very high degree of confidence. A lot of the activity that you see around is designed to extend that, but there's part of it that is fairly predictable. So that where this well, though -- we just drilled -- just completing a 2-well pad in this area. The wells are 1,000-barrel-a-day wells. That's oil. We've got 3 million or 4 million a day of gas. But it's pretty easy to see. You understand this is not a seismic shift, talking about 1 rig, 0.5 rig for a year, perhaps, basically 0.5 rig for a year basis. This is $30 million, $40 million shift.

So and it's really driven by the high degree of non-op drilling by people around us in Karnes. So we -- Karnes will be important, and we still see a lot of acquisition opportunities in Karnes over the next few years. So I think we have to get to the point where we know the pad drilling will work. The wells have fairly predictable ultimate recoverable reserves, and we know we can bring the cost down materially in this environment. So yes, there's no reason not to do it, but again, we're driven -- I think sometimes people -- we're driven principally, we start out with the 60%. We're only going to spend 60%. We're not going to spend 100%. If we wanted to make -- we can make any production growth we wanted just by doing all Karnes wells. The problem is that the wells have a sharp decline.

And so what we're trying to do is build a base of production that doesn't decline as much, so it -- this is easier to manage. Karnes is wonderful, but it's actually more wonderful when oil's $60 or $70, because you know -- oil comes back so quick that you know what you're going to get. When oil prices are lower, you cut back and try to build a base for the future, not very complicated. But I think the shift is pretty small in the total. The only issue it has is that because the Giddings wells don't pop up by huge numbers in the first week, it takes 90 days really for them to settle down. It will slow the growth rate. But as the year progresses and as we go into next year, the growth rate will start to show up because you'll have this base building. So I don't think there's a lot of question about the -- this size program, how well it will do.

We continue to be surprised at the extent of areas that we didn't think would be so good and are working out okay. Now they're not proven or whatever yet. But at this point, I think we'd be remiss in not expanding the program, but we are determined not to significantly exceed the 60%. If we exceed the 60%, it's because of a forecasting failure on our part, price of oil goes down, and that's all, but we can't stop the drilling. But that's what drives our business. Our business is not driven on volume growth, it's based on financial strength.

No. I agree with the shift, and hopefully, the market better realizes the value you have in Giddings, and then...

We also have cash on our books. And so since we're not -- if the company doesn't sell stock, then it might buy some. From our perspective, while it's unpleasant maybe for a shareholder, frankly, I'd rather buy the stock at $9 than buy it at $25.

Well, right. And Steve, you really just funneled that right into my second question was your comment just on production growth. It seems your production growth has been a little bit flat here in the last couple quarters. I know there's been some comments out there. I think that's what some investors has been commenting and maybe what's been hitting the stock.

Could you -- you started to talk about this a little bit, to give your thoughts on how you and Chris view, just looking at production growth versus maybe free cash flow or other metrics that you all might use?

Yes. Production growth is an outcome of the cash flow discipline. It's not the goal. So the goal is to use the money as efficiently as possible to generate as much value as possible. Value is in reserves and cash flow, current cash flow. But we could make growth any number you want. If we ran 85% for the whole year, we'd probably grow 15%. So we're not going to do that. It takes about, near as I can figure -- takes about 50% of cash flow, [the keys are to] keep us flat. So and anything above that will make us grow some. So we could drill more Karnes wells and make whatever number somebody wanted, but that's not the business model we told investors we're doing.

The locations don't go away for us. We don't have any debt, so we don't have any debt-coverage issues that some people have. We're not trying to -- make sure our revolver stays steady. So we're not going to trip any covenants. So other people have different issues and they want growth.

I mean the world oil demand is going to grow, let's say less than 1% this year and people want the production to grow 20% and they wonder why oil prices are not so attractive, and it's not the Saudis. So I -- everybody's -- you got to be -- live within your cash flow. And when oil prices are low, you have lower activity. When oil prices are high, you drill more, and that's way the industry should react. Certainly the gas industry ought to react that way. Anyway, probably more than you wanted to hear.

The next question comes from Jeff Grampp of Northland Capital Management.

Steve, I was wondering kind of big picture, you mentioned how the shift to Giddings and allocating more capital and growing that base kind of sounds like provides a better, I guess stable production base for you guys to build off of going forward. And you also mentioned that -- kind of that, I guess the 50% cash flow kind of maintenance level mode. I was just kind of wondering is this all part of, I guess a bigger plan longer-term to kind of set up the dividend story for you guys and to the extent you feel comfortable putting out any kind of time line for when you think the business matures to that level? But was just kind of wondering, is that kind of part of the strategy? Or is it really just more straightforward and just...

Well, no. No. Generally, having money is always good. And so it's always good to have money because it has flexibility. I generally believe in dividends as a way of providing management with discipline. But if management's undisciplined, they'll do stupid things with the money like pay themselves $5 million a year. And so I think we just got to -- we'll get to the dividends over time. I do think that this year, there will be some bolt-on acquisition opportunities in Karnes as people get over the roller coaster ride they've been on. And we'd be able to add -- get our total production up some. Some will come from drilling and some will come from bolt-ons.

I don't like debt. And I think we're -- I think it's a practical matter. I think this year will be a busy year for us. And once we get to a more stable base and a little larger, if I can spread more overhead over a stable base, I think that's the time to be talking about dividends. We're not going to be able to compete with Exxon for dividends or the [Occidental Petroleum Corporation] or whatever for dividends.

So you're just not going to be able to compete with that sort of situation. So we got to compete on a value -- total-value basis. I don't -- I think there's no question about our commitment to free cash and not wasting the money. Maybe with some of the others, the dividend just proves that they now have religion, but I don't know what the religion is.

Understood. And for my follow-up, just going back to Giddings here. Was just kind of wondering, I guess kind of the more medium-term plan. So the second rig comes in, is the idea that, that is there for the foreseeable future and to the extent you mentioned if kind of the front end of the curve bumps up, Karnes becomes more attractive, I mean is that kind of a catalyst to (inaudible) back in?

That's the catalyst. That's the catalyst. If we're creating -- I think, we'll create more value with the rig on Giddings right now. If (inaudible) goes down or the price of oil goes up, we'll have more cash anyway. So I would expect we'd put the rig back into Karnes. So but I would think a year from now, we'd probably had the rig back in Karnes, would be my guess if everything works okay, and we still might have 2 rigs in Giddings.

So I -- my hope is to run 2 rigs in Giddings, 1 in Karnes and then 1 shadow rig essentially from the non-op. So that's where we'd like to be. But right now, it doesn't -- that doesn't tie with the 60%. And when we get too -- go ahead.

The idea would be with, I guess some growth from Giddings, coupled with maybe a couple bucks on the oil price, that can kind of allow you to put some more capital into Karnes without breaking the model?

That's right. That's right. We can't break the model. You could always fool yourself into spending more money. That's the history of the industry.

The next question comes from Leo Mariani of KeyBanc.

Just a question on free cash flow. Obviously, you guys talked about some potential M&A later this year. I guess you really didn't do any deals in 4Q. It doesn't sound like anything's happening in the short term. It sounds like the dividends are way off. We obviously had the buyback that you did in 4Q, which seemed kind of one-off on the Class Bs.

Just wanted to get a sense is, is that something we could kind of see in the future is potentially purchasing chunks of some of those Class Bs from time-to-time in the absence of M&A here in '20?

I sure hope so. But again, I don't control that process. I'd like to, but I don't control the process. It's controlled by EnerVest, and I have no idea what their plans are. So I got a pretty high degree of confidence in the bolt-ons this year. So I wouldn't take my comments to it as all that definitive. But we've got a number of people that are out there that tried to sell last year that couldn't sell. They thought they might have a window when the oil price went up for a couple hours. Prices come down, they get deflated. In the end, they're better off. There's never been a bad time in the last decade to sell your oil assets, small oil assets.

Yes. No, that makes sense, for sure. And I guess just wanted to touch on some of the non-op activity in the Karnes area. I guess you guys were saying, hey, it's up 15% to 20% this year. I guess that being said, I mean certainly, production lower, it sounds like in the first quarter, a lot of those wells may be coming on later. I just wanted to get a sense, did you guys have kind of good visibility on some of the timing of that production coming on in the Karnes area just given the larger number of wells this year?

We got pretty good timing. We're pretty good. We have AFEs from them and a lot of those wells have been drilled and there's completion crews on them. So it -- what you -- what it looks like sort of big picture is it was slow in the beginning of this first quarter, the production. And then it's picked up sharply as the wells that were DUCs at the end of the year have been completed. So I think you're -- so that's back-end loaded. And of course, you got half a quarter gone already. So I -- so as we go into second quarter, production should be up nicely.

Okay. No, that's helpful for sure. And I guess you guys also said that there were 2 recent wells, I guess in the Giddings area that I guess weren't part of some of the prepared press release comments and maybe just recently fracked. I guess those sounded particularly strong. I know you guys said you're generally been surprised to the upside by the predictive model you guys are using. Just anything unique about those 2 new wells or anything? Is it sort of in a new area or...

No. No. They're actually in the area that we have a high degree of confidence in, and we did it on a -- off a pad. So the wells, basically, the fact that the wells are the same, obviously went in different directions. But the wells are the same gives us confidence that the model is not producing a variable result, but actually a real result.

That's helpful. And I guess that also gives you confidence on the well cost reductions on the 20% as well.

That's right. And I would hope for more than 20%, to be honest. They only let me set 20%.

The next question comes from Dun McIntosh of Johnson Rice.

Just wanted to clarify on the 2 new Giddings wells that Leo was just asking about. Are those 2 different than earlier in the call when you were referencing how you found that you all had an area like a 70,000 contiguous acre block that you were -- it was more of a step-out and that you're highly confident? Or are those the same 2 wells you're talking about in both instances? [The biggest blocks you're doing].

No. This acreage block is a part that we have a high degree of confidence in. These 2 new wells off the pad are within that block. The other wells are way off the block. All the other wells we've talked about are nowhere near the block.

Okay. That's what I thought. Just wanted to clear up on that. And then on the third quarter, you talked about bringing on 3 new wells at Giddings for the fourth quarter. I mean obviously, you came in with the 2. Just wondering what kind of pushed that third one out. CapEx came in a little lower as well there. So helped you on that end, but...

It just got delayed. And it's I think on now, sort of.

Okay. Great. And then for a quick follow-up, on the cost side, LOE and transportation came in ahead of what we were looking for. I'm just wondering if kind of the $3.60, $3.70, is that kind of something that we can look at going forward? And what's -- what are kind of the drivers there on LOE with -- as Giddings does become a bigger part of the program?

Yes, the LOE and the GP&T is -- should be fairly consistent going forward. I mean I don't...

The Giddings area is -- Giddings gets -- a lot of Giddings oil is trucked. And so -- and we're -- as the production builds up, we're trying to figure out ways to reduce the trucking. And so we may do something to fix that because we think the volumes are so -- the volumes are going to be large enough that we need to do something more permanent than put another truck.

The next question comes from Kashy Harrison of Simmons Energy.

Steve, in your prepared remarks, you talked about the 400 locations with 1,000 barrels a day of the 90-day mark, 3 million cubic feet of gas. Really appreciate the color there. If I recall, you've also talked about Giddings having 1,000 locations conservatively in prior presentations. And so when you think about those remaining 600 locations that you've conservatively highlighted, how would we think about an average oil rate to go along with the 600?

I don't know. Your -- the 70,000 was sort of an example of 1 area. So we didn't -- we got several more areas. And in some of those areas, we only have 1 or 2 wells. In this larger block, we've got more. So I don't really know, but it's just hard to do it. Understand we're probably not going to get to this in anybody's -- with 2 rigs, it will take the rest of my -- certainly my natural life, maybe yours, to drill it up.

So I -- our interest is basically to find it and then figure out what the program, the development will be, and that's going to take us a while. So I think the only point of the 400 locations was to say we've got 10 years of activity as a minimum at -- with 2 rigs, maybe more. And you should view it as -- I don't know when we're -- we'll do some exploration to sort of square it up. Some of those areas may be better than this block, by the way. So I -- we just are not in a position to sort of forecast beyond this because it's plenty for now.

Got it. Got it. And then you also talked about reducing the well cost by 20% or even more in 2020. Can you give us a sense of CapEx per well or CapEx per rig in the Giddings field today? And just based on what you know about the characteristics of the field, do you think it's possible that those costs could eventually come down to the cost around the Karnes area?

So the wells to this point, we've done -- we've taken core, there's been a lot of science fair sort of stuff and -- to gather data so we sort of understand what we're doing. So as we drop that, the wells should be in the $7 million range. The formation is deeper here than in Karnes. And because we have so much acreage, we're drilling 6,000 foot laterals at this point because we know we're not really restricted by acreage.

So and we may drill longer laterals at some point. It's a more complicated drilling because of the field. But so I think around $7 million right now. And I would hope, at some point, we'd be down in the $5.5 million to $6 million. But I think that's a little ways away.

Got it. No, that's also very helpful. And then finally, I mean, I know you've talked about having a high confidence on bolt-ons for 2020. We've heard of assets outside the Permian, sounds like they may be going for PDP, PV15s or maybe even PV20s these days. And so just wondering what you're seeing on valuations in general in the Eagle Ford and the A&D space.

Yes. I mean the problem is there's no -- we make a bid, we win, but they don't sell because they want more. The fundamental issue is that we're willing to pay a reasonable price for the PDPs and we're not willing to pay very much for locations. And they want money for the locations because 2 years ago, some guy told them the locations were $5 million each or something. And so -- and they've marked -- a lot of these are private equity people that have mark-to-market of their assets on some basis that I don't quite comprehend. So and don't want to take -- they're not prepared at this point to take a loss. At some point, they'll take the hit. But right now, they're -- they don't really want to take the loss.

But I'm not really concerned that there's not a lot of buyers for this sort of asset. The only value really is in -- for somebody who can integrate the assets and spread your overhead. These companies may make $8,000, $9,000 $10,000 a day, and they got overhead of $30 million or $40 million. We can make that all go away, and so that's the only value. Somebody couldn't buy it and run this asset and then make any money with -- for that kind of overhead.

So our principal objective is not just more locations, that would be nice, but also to spread overhead because that's a real value-add that we have compared to somebody else who's going to start all over again.

This concludes the Q&A session and the Magnolia Oil Fourth Quarter and Full Year 2019 Results Conference Call. Thank you for attending today's presentation.

Thank you.

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