Matador Resources Co (MTDR) 2013 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the fourth-quarter and full-year 2013 Matador Resources Company earnings conference call. My name is Carolyn and I will be your operator for today. At this time all participants are in a listen-only mode. We will facilitate a question and answer session at the end of the conference.

(Operator Instructions)

As a reminder, the conference is being recorded for replay purposes, and the replay will be available through Thursday, April 3, 2014 as discussed and described in the Company's earnings release issued yesterday. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the Company's financial performance. Reconciliations of such non-GAAP financial measures with the comparable financial measures calculated in accordance with GAAP are contained at the end of the Company's earnings release.

As a reminder, certain statements included in this morning's presentation may be forward-looking and reflect the Company's current expectations or forecasts of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the Company's earnings release, its most recent annual report on Form 10-K, and any subsequent quarterly reports on Form 10-Q.

I would now like to turn the call over to Joe Foran, Chairman and CEO. You may proceed.

Thank you, Carolyn. And good morning to everyone on the line. And thank you for participating in our fourth-quarter and full-year 2013 earnings conference call. We appreciate your time and interest this morning very much.

There are three key points we would like to emphasize on this call. First, 2013 was a record year for Matador, and while we are very proud of our accomplishments this year, which were primarily driven by our operational success in the Eagle Ford and the addition of the Permian Basin as one of our main operating areas, we believe 2014 will be even better, as we expect to increase annual production from two million barrels to three million barrels.

Second, we continue to pick up high-quality acreage in good neighborhoods across all of our operating areas, and we plan to build our presence most dramatically in the Permian Basin. Accordingly, we are pleased to report positive results on our first three exploration wells in the first three acreage areas we have tested in the Permian Basin.

Third, our liquidity position remains strong, as our bank group just agreed to increase our borrowing base from $350 million to $385 million, and which leaves us -- we have at the end of the year $200 million borrowed, approximately. And then our 2014 adjusted EBITDA is expected to grow another 35% and 40% from our 2013 EBITDA.

In regards to the 2013 accomplishments, we would like to take a minute and highlight a number of operating and financial records for Matador that were accomplished in 2013. These highlights include growing oil production by more than 76% to 2.133 million barrels of oil, from just over 1.2 million barrels in 2012, and almost 14-fold from the 154,000 barrels we produced in 2011.

Second, our adjusted EBITDA grew to $191.8 million in 2013, an increase of 65% from $115.9 million in 2012, and almost four-fold from $49.9 million in 2011. Three, our share price began 2013 at $8.20 per share and ended the year at $18.64 per share. We did a secondary offering in September 2013 at $15.25 per share, and the share price closed last week at a record high of $25.08. We are pleased to say that these three operational and financial metrics were all the best in Matador's history, and either above or near the high end of 2013 guidance as revised upward on November 6, 2013.

Matador expects to continue this pace of growth in 2014. This success comes primarily from an Eagle Ford drilling program in South Texas that continues to be the heart of our operations and where we have been able to consistently drill better wells for less money. Specifically, across the play, we are continuing to decrease our drilling times per well from spud to total depth, reduce overall drilling and completion costs, and continuing to refine and improve our frac designs to enhance well productivity and ultimate hydrocarbon recovery.

We are also encouraged by the early results from our down spacing program which has drilled seven 40- to 50-acre spaced wells. We also plan to replace one of the contracted drilling rigs in South Texas, with a new rig equipped with a walking package. This will give the Company two walking rigs operating in the play, and position us to take advantage of batch drilling operations for the balance of 2014, which we believe may save as much as $400,000 or more per well, and reduce drilling times accordingly.

Now, we would like to discuss our success build and our presence in the Permian Basin, in Southeastern New Mexico, and far West Texas. First, we have significantly added to our leasehold position in the Permian Basin, acquiring approximately 55,400 gross, 38,900 net acres to bring our total acreage position to approximately 70,800 gross, 44,800 net acres at the end of the year.

In the first 10 weeks of 2014, we have acquired an additional 7,000, 5,300 net acres in the Permian bringing our total acreage position to 77,800 gross and 50,100 net acres, at March 12, 2014. Not only do we consider this one of the best resource plays in the country, along with the Eagle Ford, but we consider the large majority of our acreage to be prospective for multiple oil and liquids rich targets, including the Wolfcamp and Bone Spring plays.

Second, along with continuing to pick up high-quality acreage in various areas, our Permian drilling program is off to a great start in 2014 with three exploratory successes. We have previously announced strong results from our first two horizontal wells in the Permian, the Ranger 33 State Com 1H, and the Dorothy White 1H. With this release, we are pleased not only to report updates on these first two wells, but also to announce the initial results from our third exploratory well, the Rustler Breaks 12-24-27 1H well, a Wolfcamp B horizontal test in Eddy County, New Mexico.

The Rustler Breaks well flowed 987 barrels of oil equivalent per day, 44% oil, including 436 barrels per day of oil and 3.3 million cubic feet per day of natural gas at 3,000 pounds on a 24/64 inch choke during a 24-hour potential test. It is now awaiting the pipeline. As with the previous two Permian wells, this result exceeded our original expectations, and we are very encouraged by the Rustler Breaks wells early performance, especially the way it has exhibited significantly better oil and natural gas flow rates at a higher flowing surface pressures, on comparable choke sizes than compared to other Wolfcamp B tests in the immediate vicinity.

As mentioned earlier, we are also pleased to announce our liquidity position remains solid after our bank group increased our borrowing base from $350 million to $385 million at March 12, 2014, based on our lender's review of our December 31, 2013 oil and natural gas reserves. We will use this additional borrowing capacity along with our cash flows to continue to fund our ongoing three-rig program in the Eagle Ford and the Permian Basin.

I would like to acknowledge our thanks and appreciation to our bank group, led by RBC, Comerica, Bank of Montreal, Citi, SunTrust, Scotia, Wells Fargo, and Iberia for their strong support and interest in growing our relationship.

Finally, we are affirming our pace of growth will be similar in 2014 to what it has been in the past, and our specific full-year 2014 guidance metrics, which we previously announced at analyst day on December 12, 2013, are as follows. Capital expenditures of $440 million. Oil production of 2.8 million to 3.1 million barrels. Natural gas production of 13.5 million to 15 billion cubic feet. Oil and natural gas revenues of $325 million to $355 million. Adjusted EBITDA of $235 million to $265 million based on projected prices of $95 oil and $4.25 per Mcf of gas.

With that, I would like to introduce everybody from Matador Senior staff, joining me in this call, who have all contributed greatly to these results and who are standing by for any questions you may have. We have Matt Hairford, President; David Lancaster, Executive Vice President; Chief Operating Officer, and Chief Financial Officer; David Nicklin, Executive Director of Exploration; Ryan London, Vice President and General Manager; Brad Robinson, Vice President of Reservoir Engineering and Chief Technology Officer, as well as other key members of the Senior staff and operating committee. I would now like to turn the call over to Carolyn and we will be pleased to take all of your questions.

(Operator Instructions)

The first question is from the line of Irene Haas from Wunderlich Securities. Please go ahead.

Yes, hey, good morning, everybody.

I have a question on your Rustler Breaks well. It is a really interesting well because this is probably one of the few Wolfcamp wells drilled in this part of Eddy County, and like you mentioned earlier it has definitely performed much better than the close by wells. Do you have an average of what the other Wolfcamp wells are doing? And what are they targeting, is it the B? And for yourself, would you see other targets in A or C or B within this vicinity? So that's my question.

Hi, Irene this is David Lancaster. How are you today?

Great.

To answer your question, the other wells that we have seen information on right there in Eddy County have probably tested on the order of maybe 200, 250-barrels a day, or 1.5 million to 2 million a day in terms of natural gas production, and at lower flowing pressures than what we saw in the Rustler Breaks well. So we were really pleased to get our results at 3.3 million and 450-barrels a day, and that was flowing at about 3,000 pounds surface pressure on still a relatively small 24/64th choke. So we are very encouraged by that result.

The other wells right there in the immediate vicinity were in fact targeting the Wolfcamp B, so I think that those are comparable tests. And I think your other question was do we see other horizons in the Wolfcamp at that interval. I might ask David Nicklin to elaborate a little more on that, but the answer is yes, we do see the potential for even other horizons there on that acreage.

Irene, it is David here. And I would just echo what David said. Yes indeed we do see additional horizons in that area. There are Bone Spring -- there are multiple producing areas, horizons within the Bone Spring, and we are still curious about additional levels within the Wolfcamp.

So we do see quite a bit more potential. We're continuing to appraise all of the geology in the area. And monitoring additional producers in and around us.

Irene, I might say, this is David again, I think one thing that we found encouraging by this initial well result is that we liked the looks of the Wolfcamp B there across that portion of the acreage position. And so that may become a bit of an anchor for us for the rest of our program, and then at some of the other intervals, we have a chance to test them. We feel pretty good about that. And I think Wolfcamp D is also another interval that we will probably look to test down the road here.

Okay, great, thank you.

Yes, ma'am.

Thank you for that question. The next question we have comes from the line of Scott Hanold from RBC. Please go ahead.

Thanks, good morning, guys.

Hey, Scott.

A question on the Eagle Ford down spacing. It looks like the results were favorable relative to some of the prior wells that had been drilled there. A couple of integrated questions, can you quantify, now that you feel pretty confident in the 40-acre development in that Karnes County acreage, what does that mean for your drilling inventory? I know you all talked about 270 gross wells in the Eagle Ford. What potentially does this do?

Scott, this is Ryan. I think we can answer that question, just I think the inventory right now, basically has most of the 40-acre locations already in the inventory for the central and the west. We're still reluctant to put in the eight locations in the inventory for the east.

Although we're showing a lot of good results so far, we're still in the investigation period for the 40-acre spacing. And in our central, we show in our release that we have had some of our most recent 40-acre wells are actually some of the best wells we drilled in the Eagle Ford, or in the central regardless of spacing.

But we have had a little more variable results over in our Western area. I think that is just simply due to some of the existing producers out there, have a variety of different fracture generations, so they, of course, have a variety of different fracture geometries. When I say fracture geometry, I'm talking about the width of the fracture pattern, and as we go in there and frac with these 40-acre offset wells, we're encountering different levels of interference.

As we move, march westward in some our acreage, specifically our Martin Ranch, we are going to be getting into undrilled territories where we are going to have a little bit more consistent results, we believe. And looking into the future six months to a year, I think then we're going to finally have enough information necessary to really get our hands on what is going to be the appropriate spacing for the different areas. Does that answer your question, Scott?

Yes, and just maybe one little tweak within the question, is you talked about seven wells drilled at 40- to 50-acre spacing, and you also mentioned that -- I think you specifically mentioned five wells are kind of outperforming on the specific lease.

What about the other two wells? Are those also outperforming or is there something different with those?

In the central acreage specifically, all of the down spaced wells have done very well. I think three of the wells were adjacent to more modern fracturing generations. So that's another example or a testament that it is a function of not only the generation 6 frac, but the existing producing wells, as well, and what kind of fracture was put on those wells.

The wells that did over 1,000-barrels a day with 3,500 pounds of pressure, those were adjacent to generation 2 fracs, which as you remember were relatively smallish. And so the results there are really encouraging for when we are going into new territories, or we're fracking adjacent to existing small fracs. Like I said in the Martin Ranch where we have generation 2, 3, 4, and 5 fracs, that really is what makes it a little bit more complex.

Okay. But what I should take away, if I'm hearing you correct, and I just want to clarify this, that if regardless if the down spacing well was near a more recent generation or an older generation, you're still seeing good well performance coming, favorable well performance on the down spacing?

Definitely, Scott. I think overall, our 40-acre program looks very positive and we're still very encouraged. We continue to plan and forecast for the years to come on 40-acre spacing, and on the new leases that we have gotten, where we're targeting 40-acre spacing as the appropriate development pattern.

Scott, this is Matt. And I just kind of want to add to that. The other thing that really encourages is, as you have seen and we talked about it, reduced well costs, you hear us talk about drilling better wells for less money and that's exactly what we are doing here.

Absolutely. All right. I appreciate that guys. Thanks.

Just one last follow-up, Scott. This is Joe. I think the last wells have been as low as $6 million.

That's right, Joe and that greatly impacts the economics with the generation 6 frac and improves production on that. So as Ryan said, we are really encouraged.

Some of our most recent wells have actually dipped below the $6 million range. In our Western acreage, you may recall we have been estimating $6 million to $7 million for drill and complete costs, and here recently in the last several quarters, we have dipped below that $6 million several times. So we're definitely pointing towards the low end of that range for the wells in the West.

Thank you. Ladies and gentlemen, the next question comes from the line of Neal Dingmann from SunTrust. Please go ahead.

Good morning, guys. Good quarter. Say, Joe, obviously for Joe, for you or the guys, you continue to get these Eagle Ford costs down just to remarkably low costs, and the drilling days, I think you mentioned even getting some wells down as low as eight days. What are you guys budgeting on both of those fronts on well costs for Eagle Ford for the remainder of this year, and total time line on those?

I can answer that question. Again, this is Ryan. What we forecasted for this year and actually beyond this year, is like I said. It is generally $6 million to $7 million in the West. $7 million to $8 million in the Central. And $8 million to $10 million in the East.

And those are kind of generic numbers. All of our forecast for costs are very specific to the location, to the lateral length, to the depth, and we take all of those factors into account when we are generating our capital forecast. But I think on average, those are the types of numbers we are looking at.

We are also expecting to enjoy additional savings on the drilling side, simply just to the addition of this walking rig in our Central acreage. We reduced our drilling costs by over $300,000 per well on our first four-well pad in the Eagle Ford by using the batch-style drilling and the walking rig.

We are forecasting that we are going to continue to have at least that much, and as much as $400,000 in cost savings, and now that we are adding the second rig, we expect to enjoy that on all of the wells we drill in the Eagle Ford.

All right, thank you all.

Thanks, Neal.

Thank you. The next question we have comes from the line of Ben Wyatt from Stephens. Please go ahead.

Good morning, guys.

Hi, Ben.

Just one quick one. Can you guys remind us how lease expirations look like out in the Permian?

Ben, for the most part, they range from being some part of the acreage is HBP, and then some are -- a good part of them are government leases; if they're a state they have 5 years, and if they're federal they have 10 years. We don't have any expirations that are coming up in the near term in 2014. Really, our first ones that we have -- any are really in 2015, is that right Van?

Joe, that's right. There may be one or two small leases that have expirations this year, but those have already been addressed in our drilling schedule, and so we don't anticipate having any expirations this year. And I think we have got a pretty good handle on next year, as well. So it will be some time before we get down into any crunch period.

But the overwhelming majority have 3 years and 10 years, or they're HBP.

That's correct.

Does that help, Ben?

Yes, sir. And a follow-up to what Irene brought up with the first question. As you go around and do your appraisal work and actually hold this acreage, will you go as deep as the Wolfcamp D just to hold, from all of those zones up, even though you might be targeting just the B for now?

Ben, you have actually asked a good question, and what is one of the differences between the Delaware basin and South Texas. On all of the government leases, the state and the federal, there is no depth limitation. So you hold all rights, all depth, with your well. So it doesn't have the Pugh clauses that you encounter in South Texas.

So even if you have a 3,000-foot well, you will hold all of the deep rights. And generally one well will hold the whole tract. Although they're not 3,000-acre tracts, they will hold the 320 or the 640 or whatever size that it is. Ben, would you add to that?

No Joe, I think you covered it. It is important to note, too, that our drilling schedule plans have addressed things like that where we may have a Pugh clause on the Texas side. So our intent would be to, just as you say, go deeper and make sure that we're holding all of the prospective zones that we have identified.

Ben, one thing that we might bring up, this is David, with regard to just the Texas side, is that our main asset right now there in Loving County is one that's HBP by a shallower production, and so we really have -- we've got all of the Wolfcamp rights, and so we've got a lot of luxury there both in time and in what we want to do, because all rights and all depths are held by some shallower production there.

Very good. Well, I appreciate it, guys. I will get back in the queue.

Thank you, Ben.

Thank you, ladies and gentlemen.

(Operator Instructions)

The next question we have comes from the line of Brian Corales from Howard Weil. Please go ahead.

Good morning, guys.

Hey, Brian.

I was calling on the Permian, the Twin Lakes acreage, it looks like that is the biggest growth area. Do you all plan to put the rig up there and test some of that acreage in 2014?

Yes, it is David Nicklin here, Brian, and yes we do. We have a prospect up there. It is going to be primarily a data well.

We're planning a full formation evaluation of the Wolfcamp, or what we might call the Pennsylvanian shale in that area. It is several hundred feet thick out there. And what we plan to do is get a full set of logs and cores through that.

Brian, this is Joe again. I would add to you that that is the fourth area. We feel like right now we have four main areas in the Permian, that's the Wolf area, the Rustler Breaks, the Ranger, and this is the fourth area. Just as we have done on the other three, we plan a data well, you get cores, full data across that. Since almost all of those are new leases, and most of them are government leases, we have five years.

So we have the time to do a fairly deliberate, methodical, take what we are learning in these other areas, and apply it up there. And so that is going to be done this year. And we are pretty excited about that area. The more we've studied, the more we liked it.

I'll add Brian, one more thing. This is Ryan. That well we intend to drill, it is going to be a vertical well with no completion and we intend to do that early this summer.

And Brian, this is Matt again. I might just add too that is very consistent with what we've done in the past starting back in the Haynesville days. We did the same thing in Haynesville. We did it down in the Eagle Ford. The first wells we drilled were data collection wells. We got whole core logs and rotary core logs, and so it is very consistent with what we have done in the past.

Kind of a follow-on to that, based on these four areas, is there an area that you prefer to add acreage or are some of the areas like Wolf, just very hard to get leasehold? Is that why the majority of leases have been added in Twin Lakes? Is that the future upside of where you are going to have additional growth in the acreage side?

You're talking to a group; we have not all been at one mind on some of this. I think most of our acreage acquisitions have been opportunistic. It has been a function of how we fit it in, what the price is, the length of the term, where we are going.

We are adding acreage in all four areas. So we like them all right now. And I don't think that as a group we have one preference over the other, other than it just comes down to economics and timing and what makes the most sense among most of us. Van?

The only thing I would add, Joe, is that our technical analysis of these areas ahead of time allows us to be opportunistic, and we are happy to get acreage in any of the areas. I think what you would see if you broke down the most recent acreage additions is that they're spread pretty evenly through the four areas. Every area is very competitive, and we're seeing many other companies trying to lease in the same areas we are. So, I would just say we're happy to get it wherever we are and try to expand the positions we have.

I might just add, Brian, this is David, I think one reason that we also ended up with a very nice position up in the Twin Lakes area, is that I think that we may have been a little ahead of the pack there in terms of recognizing that there may be real potential here to the Wolfcamp, and particularly the Wolfcamp D. And so we had been leasing in that area for close to a year now, and I think that enables us to put together a nice position, and at a very, very attractive investment relative to some of the other acreage.

We're probably in the $300 and $400 an acre area. So, I think just the fact that we may have had this idea a little earlier has enabled us to add to that position a little more aggressively. But as you heard from what Van and Joe have said, we still have opportunities in all of the three areas, and are looking at opportunities all the time.

Could I just say quickly, Brian, it is David Nicklin here again. I would just like to say this. That each of these areas that we have highlighted are areas that have -- they're all slightly different from one another. They have unique characteristics.

But one of the wonderful things about this whole play is that you really can find prospectively in each of these areas with these different sets of circumstances. And I think that is very -- that is what makes it such an exciting play to be in for me as an explorer. There are some great characteristics in all of the areas.

That was very helpful. I mean because you all have been able to grow this acreage position pretty impressively. And if I can squeeze one more, maybe tack on to that, do you think you can double the acreage from here, or are you happy with what you have, or is it just going to continue to see what is available?

Brian, one thing, let me just say this. We tried to be balanced in there and spread our dollars, relatively evenly through these areas. And when you ask the question, can we double, the answer is yes. There is acreage available depending on what you're willing to pay for it. But you've got to balance that with your ability to drill and your people and your growth; you don't want to get over your skis.

We're all in here, chuckling a little bit because you know Van Singleton, what a great job he does on land, and everybody in here turned and pointed to Van, and said do we let him out, because when he goes out for coffee, he comes back with two deals. (laughter)

So we could, but again, how Matador has always gone is we want to be sure that we are buying quality acreage that we are going to drill in the Eagle Ford very little, and in the Haynesville both. Very little acreage we have had, we had expire on us that we didn't validate and turn into wells. And we want to do the same thing in the Delaware, and not just buy acreage to buy acreage, but be sure it is part of a coordinated plan and fits into the overall plans for the area.

So yes, we are still seeing plenty of opportunities out there. And we wanted to get these appraisal wells in. And now, we are evaluating it. But we want it to be proportionate to our drilling capital and proportionate to our size.

All right. Thanks, guys.

Matt, David --

No, sir, I think that covers it real well.

That sums it up well.

Thank you, Brian.

Thank you. The next question we have comes from the line of Gabe Daoud from Jefferies. Please go ahead.

Good morning, guys.

Good morning, Gabe.

Going back to the Eagle Ford and specifically generation 6 frac design, I believe in the release you mentioned four Martin Ranch wells drilled that performed pretty well compared to wells drilled on the earlier design. Wondering if maybe you could quantify that, or talk a little bit about the rates between all wells drilled on generation 6 versus generation 5?

Gabe, this is Ryan. And I can comment a little on the generation 6 design, but I think we are going to abstain from giving too much information on the production, really. I think what we've tried to do in the past is just do things on a relative basis; due to the variety of lateral lengths and some of the shut-ins that some of the wells experienced, it is real hard to give any clarity on that answer until we have a little bit longer-term production.

What we can say is that the generation 6 designs, on an equivalent basis, if you frac at generation 6 design next to a 40-acre offset, and a generation 5 design next to a 40-acre offset, given the same conditions, every time we have moved through the frac generations, the more modern frac generation has performed better. And I would say that has remained consistent through the generation 6 design and across all of our acreage.

Does that help answer the question?

Thanks, Ryan. No, that is helpful. And I guess just a follow-up to that.

So is there a particular lease or even an acreage of oil, liquids, or gas that you think performs better on a generation 6? And then do you see potential to increase the design from generation 6? Maybe go up to about 2,500 pounds per lateral foot?

To answer your question on the generation 6, where we are going next, absolutely. We have averaged about 6 months with each frac generation, which is about the amount of production data that requires for us to really evolve the frac generation in the right direction.

We are working on the generation 7 design, which we will probably have, will start sometime this summer. And we expect that the generation 7 design is probably going to be more about the fracture geometry. In other words, our perforation schematic, rather than any more sand or any more fluid. We feel like we have kind of dialed in in that regard, and we feel like from this point forward it is going to be more about altering that fracture geometry, which would be a more appropriate for the 40-acre spacing.

Got you. Thanks. And then if I could just --

Hey, Joe.

One other thing, Ryan is trying to get in.

I was just saying I think everything we are doing from this point is really to tailor our frac designs to 40-acre spacing program. And I think that the other thing that has an impact on that is the rock quality. Somewhere in the Central area, in the Eastern area, it is different rock quality.

And so we have different designs for all of the different areas. It is not one size fits all. Everything is very specific to the spacing, the depth, the heat, the rock quality, all of that ties into our fracture design. And when we speak about generation 6 and generation 7, it is not necessarily consistent through all of the acreage because of all of those influences.

Got you. Very helpful. Thanks, Ryan. Thanks.

Thanks, Gabe.

Thank you. The next question we have comes from the line of Mike Scialla from Stifel. Please go ahead.

Good morning, everybody.

Hey, Mike.

Wondering if you can give an expected EUR for the Dorothy White and Ranger State wells at this point?

Okay. Brad Robinson, VP of Engineering.

Good morning, Mike. Yes, at this point, it is a bit early, but we knew this area was a good area, and expected EURs somewhere in the 400,000 to 500,000-barrel equivalent range. Right now, that well is performing better than expected, slightly above our type curve.

So we are expecting to probably increase those numbers once we get a little history. But it's still a bit early to try and do a projection. We only got a few weeks, or a month or so of history. But we're expecting those numbers to go up.

So it is running more than slightly, and it has gone two months, so we're optimistic those will increase when we have a little more history, Mike.

Okay, so both of them you're feeling at this point are -- if they continue to perform the way they are, they are both going to be better than a 500,000 barrels?

Yes, I think that is it right. And the other thing that I think has been encouraging to me has just been the relative consistency in the production over their early lives.

The Ranger well, if you look at the curve on it, it has produced between 400 and 500-barrels a day, just pretty solid alone for a couple of months now. And the Dorothy White, it has settled in probably between 900 and 1,000 BOE per day, of which 600 to 650 I would say, of that oil per day. And again, just keeps rocking right along between 600 and 700 barrels a day.

So I think that is the thing that I find the most encouraging, is the fact that the wells are just continuing to hang in there and we're not seeing a real sharp decline yet at all. So that is real positive, I think.

And I think that the Dorothy White, in addition to the consistency of the oil production, the pressure has remained very flat and very consistent, and not that it is just flat and consistent, it is very high. So that is what makes it so attractive to us, and so impressive in that well.

Mike, this is David Nicklin here. One of the things we have tried to do with both of these wells is that we have targeted the laterals not into shales, but into sandstones, or fine silt stones.

And those, I believe, that a part of the divergence from the decline curves that we've got regionally for some of the more resource plays, are on account of us being in these sands rather than in the shale. So I think there is a difference in performance characteristics. And they're very encouraging.

I will add to that. I think that the fact that some of the wells have landed in these sands should not take away that this is -- there is shale above and below and that we think that this Wolfcamp is going to be a resource play. We don't think that the sandstones are going to be prohibitive to tighter spacing in the future. We do think that this is resource play type rock in the Wolfcamp.

Okay. Great. And then your Rustler Breaks well looks a little gassier than the other two areas, and you mentioned that it was performing at a higher rate than some of the offset operator wells. Given that you've got more history on those offset operator wells, do you see any change in the GOR in those wells over time, or are you worried about the oil production going down there more than the other areas?

Hi, Mike. This is David.

Well, based on what we see in the other wells nearby, no, I don't think we have any concern that we are going to have a rapidly increasing GOR in these wells. We feel pretty good about that right now.

So I think that the GOR is probably about where we expect it to be, maybe even a little bit lower. And I think we feel pretty confident that based on looking at the other wells that it will kind of hang in there about where it is.

Okay. Great. If I could sneak one more in. You're drilling in the northern part of the Rustler area now, I guess --

Ranger.

Or Ranger, I'm sorry, where does the rig go after that?

Mike, this is Ryan again. The rig right now is drilling a Wolfcamp D well in the northern Ranger. It is actually going to stay put up there in northern Ranger and drill a second Bone Springs well immediately afterwards.

Great. Thank you much.

Thanks, Mike.

Thank you. The next question we have comes from the line of Ann Kohler from Imperial Capital. Please go ahead.

Great. Good morning, gentlemen. Just a couple of questions in regards to the Permian.

In light of the conversation you had about your -- the attractiveness and certainly the desire to add acreage, I think that you have around a $30 million earmarked for acreage acquisitions, land acquisitions in the Permian this year? Is that a number that you still feel comfortable with? Or given the opportunities do you think that is a number that we could see upside to?

Ann, I just think we're too early in the year to draw, to say one way or the other. What I would emphasize here is not the numbers so much as the quality of the opportunity, and that is just too early in the year to predict that.

When we're -- we see quality acreage, we will try to acquire it. And if we don't see the quality acreage, we won't spend the money. So that is a good question. But probably should save that for, say, mid-year.

Okay, I will try another one, and I am probably going to get the same answer from you. But given that the three wells that you have drilled so far, you're very encouraged and are basically performing it seems like above your expectations.

I know that you have indicated that you're looking at potentially adding another rig in the basin, potentially later this year, beginning of next year. Has the initial results changed that time frame at all?

Ann, that's another real good question, is that yes, it has altered it in just the sense that we are very encouraged and excited and want to go to the fourth rig as soon as appropriate. But we are very methodical about the way we do our appraisal work. And we haven't finished that appraisal.

And second, we expect to bring to the Permian the same type of approach in improving drilling time, drill breadths, all of that that we did in the Eagle Ford, and that process of improving our drilling is ongoing, and that's part of the timing of it. But Matt, you may want to say your point of view of when you might recommend to us to go to a fourth rig.

Ann, this is Matt. And I think the way I characterize it is, if you think back to 2012, at the time of the IPO, where we were in the Eagle Ford, it is kind of the same spot we're at in the Permian. We've had a couple of rigs that were just marching across our acreage position, delineating the different acreage blocks and figuring out what we had and how we wanted to develop it.

And I think that is just exactly where we're at in the Permian. We've got the rig and we are going to drill a few of these wells and figure out what is good and what is better and what is best. And then probably this time next year we will be talking about a development plan similar to the Eagle Ford.

And as Joe said, we are full-on expecting the improvements, similar improvements to the Permian that we had in the Eagle Ford. So a methodical approach we think is best to figure out what we've got first, and then put a development plan in place.

Ann, there is one other thing that makes the decision a little more complex, is that with recent gas prices strengthening, you can begin to expect that some operators in the Haynesville are going to do more. And we want to watch that development to see if that firms up, and that more wells are proposed in the Haynesville to drill, in which case that may have some effect on how soon we go to a fourth rig, because that is part of the managing the capital expenditure formula.

If that occurs, we are actually pretty pleased by that, because over $4, we think you can make money on that. We are also advantaged in that our deal with Chesapeake, we kept overrides on a lot of our acreage, and in most of the instances we're up there, instead of a 75% net revenue lease, we have 85% or 90% or up.

So we have a better net, and our marketing guy, Gregg Krug, has done an outstanding job continuing to get better gas contracts for us. So we feel we have considerably improved our gas pricing over in that area too. So if that comes about and people feel that better gas prices are sustainable, we are ready for that development, too. And that's why I'm saying this is a mid-year decision. We will see how things develop and where we think we can add the most value.

Great. That was perfect, Joe. And actually that was going to be my next question, was in regards to the Haynesville and your outlook for that. If I could just sneak in one more, and that is if you could maybe provide us with some guidance in regards to your tax, the tax rate that you would guide us to or how we should think of that for the year?

Hi, Ann. This is David Lancaster.

We are through the period of the valuation allowance that we had. Our tax rate was regular in the fourth quarter. I would point -- I would say 6%, I mean 36%, excuse me, which is roughly a 35% Federal rate and a 1% State rate. So that is going to be a pretty good estimate of what to use going forward.

And I think the only thing that would change that would be of course if there would be any sort of impairment that we would incur, and I do not that I anticipate that. But that is what always causes our tax rate to get funny at times. But it was essentially 36% in the fourth quarter, and that's what I would anticipate going forward.

Great. Thank you so much. I really appreciate it.

Yes, ma'am.

(Operator Instructions)

The next question we have comes from the line of Scott Hanold again from RBC. Please go ahead.

Thanks. Just a couple of follow-ups here real quickly.

Joe, you had mentioned that you have added acreage in those four key areas, and looking into the math at just the different areas and acreage positions, it looks like you might be bolting on also in potentially a fifth area, and I know you have all talked about being out in Howard County. Are you picking up more acres over on the Midland side of the basin, as well?

Scott, we are looking at some things over there. We hesitate to say too much. I don't want to guide one way or the other on that because again, we are just looking at that.

To the Delaware opportunities, we feel we're building a good footprint over there. So we could do the Midland, but we also have feel good opportunities there. So I can just say at this time they are under review. And we like -- we think there are some good areas, but we are also very pleased with what we have in the Delaware.

So that is hard to say. And I just wouldn't want to guide people either way on that issue. But it is under serious review.

Okay. But maybe I could be more specific with my question. If you look at your acreage position, and where you have identified acreages, there has been about a variance I think of around 5,000 acres somewhere around there on a net basis, specifically can you say where that is?

You mean the acreage that we have acquired in the Midland basin? The little bit that we've acquired?

Yes, so if you look at your total Permian acreage --

You're saying the 5,000 that we have acquired since the first of the year?

No, no, no. So if you look at your four key identified areas and your total acreage position, there is, I think, roughly 5,000 unaccounted for, is what I will say. Where is that 5,000?

Well, we have probably 2,000 to 2,500 in the Howard/Dawson area gross, probably about 1,500 to 2,000 net. And there is -- we actually have a few tracts in Ward County that account for some of that.

And we have some tracts in Winkler County that I think that we have been pretty consistent with for a long time sitting on the central basin platform that we said that we don't intend to drill and they're going to expire. But that is down to probably 500 or so acres now, Scott. And I think that makes up the majority of the rest of it.

Okay. So no, that definitely answers my question. That squares the circle on that.

Okay.

And again, on the Haynesville shale, so have you all been in conversation with Chesapeake? I mean, obviously, they did talk about increasing activity. Have you got any information, or how will that come to you, where you find out whether or not they are going to be drilling more on your leases now that they ramped activity up there? Is that something where ultimately you are just going to get an AFE in the mailbox?

No, Scott, you know us. We are trying to be proactive with them. We have talked to them and are meeting with them and trying to understand what they are trying to accomplish and their timing, and to get things firmed, and they're in the process of either having sent some AFEs or saying they're likely to come.

But again the AFE doesn't mean the well will get drilled. You don't know how much of that is -- they're really serious about until it actually occurs and starts coming about. So we're trying to be very proactive and we're ready for them. And when we feel that it is with sufficient assurance, we will increase our count.

We provided for 1.5 net wells right now in the Haynesville. And when our well total starts over 1, or nears the 1.5, we will update what we think is the most likely number. But I think we can feel it is going to go up. And if you were picking a number, it would go from 1.5 to, say, 3; it would double this year sometime, is what appears likely if prices continue to strengthen.

And then I think that is a big if. Because when you look at the forward curve for 2015, it makes you wonder how sustainable the current gas prices are. And so I think that if you had a forward curve that was more optimistic, we would feel more comfortable that Chesapeake is going to follow through on that. Does that make sense to you, Scott?

Yes, absolutely. That makes perfect sense.

And so until we feel -- we don't want to come out there and say we are going to drill three net wells, or double that, and then disappoint you at the end of the year. I think it is a lot more likely to go up from 1.5 than not, and I think you can count on some going up. It is just hard to estimate or to feel that it is going to happen until you see a little more confidence in the forward curve. David, you're working on that?

Yes.

Matt, you're all working with him?

Yes, I think that is fine. I think you've captured it well. And maybe all I would just add to it is, Scott, we are in communication with them. Our teams are talking to them all the time. And I think our expectation is that we are going to see some activity from them on our property.

And as we have more clarity about that, certainly we will get more information out about that. And how we think it is going to impact our forecast for the year. It is just feels a little premature right now to put something out, and as Joe says maybe have to pull it back. So we are trying to be sure that we have more clarity around this issue before we let you know what we think is going to happen.

And Scott, I want to underscore, that if it comes about, we see that as a very positive thing because of our favorable net revenue and our favorable gas contract that Gregg has come up with here. We see that as a very positive. And if they weren't, we would be looking at drilling some of the wells that we operate.

I think that is right, Joe. And the fact is, these are going to -- if they decide to do this, and they are starting proposing wells to us, these are good wells. They are going to be very -- it is in a very good area. We are in one of the better areas of the Haynesville there, in our Elm Grove area where Chesapeake is likely -- may drill some additional wells.

And so I just think that we have -- they're good investments for the Company, because they're going to be high-quality wells; our net revenue interest is very advantaged as Joe has mentioned, our pricing is going to be better than it has been because of the work that Gregg has done for us on the marketing side. So I think there are a lot of really positives about that.

And so we would be excited, but we just don't want to tell you it is going to happen if we're not sure it is going to happen.

Okay. No, that is great. I got it. Thanks.

And then one -- can I clarify, too, and David, did you all mention that Dorothy White right now is producing, still producing over 900 BOE per day? Did I hear that right? Or was I missing it?

No, you heard that right. You heard that exactly right. In fact, it is still producing between 900 and 1,000 BOE per day quite frankly, so it is doing good Scott.

Okay. No, that's great news. If I could slip in one more real quickly here, as well.

So Eagle Ford, or oil price realizations, which, obviously, are mostly Eagle Ford, were down sequentially in the quarter, but certainly that is a trend that everybody in the industry is seeing, so not too much of a surprise. When you look at some of your marketing agreements and arrangements, and where pricing is going, can you guide us to what to expect here in the next couple of quarters?

Gregg, you want to try this?

Well as far as for the Eagle Ford area, on our gas side, we are probably looking at approximately $1.50 uplift on our contracts, and I don't really see that changing too much. And that's also, that's net of everything. That's net of all of our processing fees, transport, everything.

So I don't really see that changing. We've got a nice long contract for the next few years out there, so I don't foresee that being any different going forward. Does that answer your question?

Yes.

Okay. Thank you for that call. The next call we have comes from the line of Irene Haas from Wunderlich Securities.

Yes, hi. This is a bit of a bookkeeping question.

You have 12 wells lined up for your exploration program in Delaware basin. You mentioned that you have one in the north Ranger area looking at Wolfcamp D, then are you going to draw a Bone Spring well, so that's well number two and three. Can we have some visibility where the 4th, 5th, 6th wells are going to be?

I think, as we showed you on analyst day, Irene, the 12 wells are intended to be -- there are 3 wells we have planned at Rustler Breaks, there are 6 wells that we have planned in the Ranger area, there is the 1 at Twin Lakes that we talked about a little earlier, and there's 2 additional wells at Dorothy White, or excuse me, Wolf, near the Dorothy White.

As Ryan mentioned earlier, the next well is going to be there in Ranger. Just as a quirk of the system, we have one rig in the Eagle Ford that as we replace it with the walking rig that we mentioned, we're actually going to move it to the Permian on the Wolf for a couple of wells. And that's always been planned.

So we've got this Wolfcamp D test. We've got a second Bone Spring test up in the Ranger well. There will be a couple of additional wells then coming on the Wolf prospect to test the northern and southern ends of that prospect.

And Ryan you want to comment any further on where we go after that?

The different producing horizons in those areas, those are going to be variable too, we are really trying to test all of the different horizons. Up in the Ranger area, we are going to do, as Dave mentioned, we are on a Wolfcamp D now, we will do a second Bone Springs, in the future we will do another second Bone Springs and then a third Bone Springs.

In the Rustler Breaks area we will be doing a second Bone Springs test, and then back to another Wolfcamp test. So I think it is pretty evident what we are trying to do for this year is just test all of the different horizons in all of the different areas, and that's what you will see at the end of the year and when we're done.

Great. Thank you.

Thank you. We have another question that comes from the line of Ben Wyatt from Stephens. Please go ahead.

Hi. Thanks for letting me hop back in. A couple of, again, housekeeping questions. Do you, if anyone has it, can you tell us how many puds you plan on drilling this year? If not, I can follow-up offline.

As far as an exact number, Ben, that may be the best way to do it. I wouldn't be surprised if it was on the order of 12 to 15 wells or so. I mean that is probably pretty -- plus or minus 15 is probably a pretty good number.

Very good. And then one quick one on LOE. You, I know, have given some guidance there. How should we think of that throughout the year? Should it trend lower over time, or could there be some workover activity throughout the year, or something happening in the Permian where we can see some fluctuation quarter to quarter?

Ben, that is a great question. I really appreciate you asking it. Because LOE is something we devote a lot of time to around here. It is very important to us and sometimes it doesn't get noticed.

And Bill McMann has been working with us for a good while. He has come on board full time and is now Vice President. And we're just really delighted to have him, because he has done great work down in the Eagle Ford with our artificial lift system. The gas lift, it has been very effective this year, reducing our LOE down there. And he brings that same expertise to the Permian.

We've got work to do. There is going to be some more challenges, because some of the Bone Springs will produce a little more water. But let me let you, let Bill speak for himself, and introduce him to you all, and tell you a little bit about his approach on the LOE this year.

Bill?

Yes Ben, what we have seen in the Eagle Ford is obviously, we started out, we have had -- we're spread across a pretty wide range, so we had a set of fixed costs that were fairly high. And I think you have seen those come down over time as we start to get more and more wells online and that. So we are starting to build into, or come into our fixed costs, and that is starting to lower.

I think you will continue to see us make improvements along those lines. Probably a little bit more what you'll see is some decrease in some of these variable expenses that we have as we go forward, some of our water hauling, our chemical costs, and some incremental improvements there in the Eagle Ford.

As far as the Permian Basin, we are just getting started out there, we are going to have more water, more water handling that we are doing, but we are looking into solutions there as far as water recycling and also salt water disposal, our own disposal wells. We will be higher out there, and like the Eagle Ford, I think what you will see is over time we will start to trim that back too, and improvements there.

But with the artificial lift needs, they are going to be more intense out there. You will probably see some more electric submersible pumps, moving more fluids. We have had success, the Ranger 33, as David has mentioned, has been very good. It has ridden flat. That was not a -- it was no a geo-pressured area, like the Dorothy White area. And that went on gas lift early.

But it has sat, it is sitting right around 450 barrels a day. It has been very consistent. We haven't really went to lower gas lift valves. We're still up high on the gas lift valves where we're injecting our gas. And so the well is really strong.

So the advantage out there to getting gas lift and getting it on early, it is -- and being able to move fluids out there is proof to us that we can use that and do it in other areas out there in West Texas, and do it a little more economically. A lot of folks go right to ESP and that is going to be more expensive, they can move volumes, but if we can prove we can do that with gas lift, we can move volumes and move them cheaper.

I appreciate it, guys. Thanks again.

Ben, one other thing I would add is also direct you to a Company-wide look at LOE. If the gas production comes up, because of increased activity in the Haynesville, your overall LOE number will come down because the Haynesville gas, it is going to be $0.20 and it is great. It doesn't produce any water. And will help average out the overall LOE cost. But as you can see, Bill comes with a lot of experience from Denbury. And it is something that he pays a lot of attention to, and has good ideas, and has made a difference around here.

Thank you for that question. This ends the Q&A portion of this morning's conference call. I would like to turn the call over to the CEO, Joe Foran, for closing remarks.

Thanks, Carolyn.

Thank you all again for your interest, questions, and participation. We appreciate very much your taking the extra time to visit with us, and to get this information right. We try very hard to be good stewards around here.

And I hope that as you all watch this go public, that you see the increased depth on our Executive staff and our operating group. And your questions are appreciated, and they do mean a lot to us.

The last thing that I would urge is that again, we try to make ourselves available to you, if you need to visit with us, and we will try to keep Matador going forward. And look forward to when we see all of you all in person or have a chance to visit.

And the final thing is, is I do -- there are some timing differences, when you're bringing these new wells on and you're in new areas and you're waiting for pipeline hookups. Again, we included a graph in this news release about the six-month incremental, since the first six months before we went public, and then going public these two years. And I think you begin to see that we believe we are on a good path.

We've got our challenges. But I think it is a really strong group that will address these challenges as they come up. And we keep trying to keep Matador growing in value and getting to know all of you better, too. So thanks very much. Look forward to seeing you all again soon. Bye.

Thank you. Ladies and gentlemen, thank you for your participation today. That concludes the program. You may now disconnect.