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Matador Resources Company (NYSE:MTDR)

Q4 2013 Results Earnings Conference Call

March 13, 2014 10:00 AM ET

Executives

Joe Foran - Chairman and CEO

Matt Hairford - President

David Lancaster - EVP, COO and Chief Financial Officer

David Nicklin- Executive Director of Exploration

Ryan London - VP and General Manager

Brad Robinson - VP of Reservoir Engineering and CTO

Greg Mitchell - Independent Director

Bill McMahon - Vice President

Analysts

Irene Haas - Wunderlich Securities

Scott Hanold - RBC

Neal Dingmann - SunTrust

Ben Wyatt - Stephens

Brian Corales - Howard Weil

Gab Daoud - Jefferies

Mike Scialla - Stifel

Ann Kohler - Imperial Capital

Operator

Good morning, ladies and gentlemen. Welcome to the Fourth Quarter and Full Year 2013 Matador Resources Company Earnings Conference Call. My name is [Caroline] 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 maybe forward-looking and reflect the company’s current expectations or forecast 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’d now like to turn the call over to Joe Foran, Chairman and CEO. You may proceed.

Joe Foran

Thank you, Carlene, 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're 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 is one of our main operating areas. We believe 2014 will be even better as we expect to increase annual production from 2 million barrels to 3 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 leads 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’ve produced in 2011.

Second, our adjusted EBITDA grew to a $191.8 million in 2013, an increase of 65% from a $115.9 million in 2012 and almost four-fold from $49.9 million in 2011.

Three, our share price we began in 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’re pleased to say that these 3 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 effort 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’re continuing to decrease our drilling times per well from spud to total debt reduce overall drilling and completion cost and continuing to refine and improve our frac designs to the enhanced well productivity and ultimate hydrocarbon recovery. We’re also encouraged by the early results from our downspacing program which is drill 7, 40 to 50-acre spaced wells. We also planned 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 2 walking rigs operate in the play and position us to take advantage of best 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 in the presence in the Permian Basin and Southeast 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 approximately 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 prospecting 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 flow of 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 the 24/64 choke during a 24 hour potential test. It is now [waiting] top-line.

As with the previous two Permian wells, this result exceeds our original expectations and we are very encouraged by the Rustler Breaks well’s 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 test 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 lenders’ 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, [Co America], 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 on 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 at 2.8 to 3.1 million barrels; natural gas production of 13.5 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’s senior staffs 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 Caroline, and we will be pleased to take all of your questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). The first question is from the line of Irene Haas from Wunderlich Securities. Please go ahead.

Irene Haas - Wunderlich Securities

Yes. Hey good morning everybody. I have a question…

Joe Foran

Hi Irene.

Irene Haas - Wunderlich Securities

Hi. I have a question on your Rustler Breaks well, it's 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 definitely performed much better than the close by wells. Do you sort of have an average of what the other Wolfcamp wells are doing? And what are they targeting, is it the [B] for yourself? Would you see other target in A or C or B within this vicinity? So, that's my question.

David Lancaster

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

Irene Haas - Wunderlich Securities

Great.

David Lancaster

To answer your question, yes the other wells that we've seen information on right there in Eddy County had probably tested on the order of maybe 200, 250 barrels a day and 1.5 million to 2 million a day in terms of natural gas production and at lower flowing pressures than what we saw on the Rustler Breaks well. So we were really pleased to get our results of 3.3 million and 450 barrels a day. And that was flowing at about 3,000 pound surface pressure. So they are relatively small, 24/64 choke. So, we're 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…

Irene Haas - Wunderlich Securities

Yes.

David Lancaster

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 that are on that acreage.

David Nicklin

Yes Irene, it’s David here. And I’d just echo what David said, yes indeed we do see additional horizons in that area. There are multiple producing horizons within the Bone Spring and we’re still curious about additional levels within the Wolfcamp. So, we do see quite a bit more potential where we’re continuing to appraise all the geology in the area and monitoring additional producers in and around us.

David Lancaster

Irene I might tell you, this is David again. I think one thing that we found encouraging by this initial well result is that we sort of like 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 B is also another interval that we’ll probably look to test down the road here.

Irene Haas - Wunderlich Securities

Okay, great. Thank you.

David Lancaster

Yes, ma'am.

Operator

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

Scott Hanold - RBC

Thanks. Good morning guys.

David Lancaster

Hey Scott.

Scott Hanold - RBC

Question on the Eagle Ford Basin it looks like the results were favorable relative to some of the prior wells that have been drilled there. Couple of kind of integrated questions, can you kind of quantify now that you feel you’re 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 Eagle Ford, what potentially does this do?

Ryan London

Scott this is Ryan. I think we can answer that question just I think the inventory right now basically has most of 40 acre locations in the inventory for the Central and the West. We’re still reluctant to put in the locations in the inventory for the East. Although we are showing a lot of good results so far, we are still in the kind of investigation period for the 40 acre spacing.

And I essentially show in our release that we have had some of our most recent 40 acre wells are actually some of the best wells we’ve drilled in the Eagle Ford or in the Central regardless of spacing. But we have had a little more variable result in our Western area, I think that’s just simply due to some of the existing producers out there have a variety of different fracture generations. And so they of course have a variety of different fracture geometries.

When I say fracture geometry, I am talking about the width of the fracture pattern and as we go in there and frac with these 40 acre offset wells, we are encountering different levels of interference. As we move, march Westward in some of 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 or a year I think then we are going to finally have enough information necessary to really get our hands on what’s going to be the appropriate spacing for the different areas. Is that answer to your question, Scott?

Scott Hanold - RBC

Yes. And just maybe one little [treat] within the question and 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 all performing unspecifically. What about the other two wells? Are those also all performing or is there something different with those?

Ryan London

In the Central acreage specifically all of the down space wells have done very well. I think three of the wells were adjacent to more modern fraction generation. So that’s another example or a testament that it’s a function of not only the generation six frac, but the existing producing wells as well and what kind of fracture was put on those wells. The wells on, did over a 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 the new territories or we are fracking adjacent to existing small fracs.

As we -- I said in the Martin Ranch where we have Generation 2, 3, 4 and 5 fracs that really is what makes it little bit more complex.

Scott Hanold - RBC

Okay, but what to actually take away, if I am hearing you correct, and I just want to clarify this is that regardless if the downspacing well with near 8 more recent generation and older generation, you still think good well performance coming, favorable well performance on downspacing?

Ryan London

Yes. 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 are targeting 40 acre spacing as the appropriate development pattern.

Matt Hairford

Scott, this is Matt. I just kind of want to add to that the other thing that really encourages us is the as you’ve seen and we’ve talked about it, reduced well cost. And you hear us talking about drilling there wells for less for less money and that’s exactly what we are doing here.

Scott Hanold - RBC

Absolutely, all right. I appreciate that, guys. Thanks.

Joe Foran

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

Matt Hairford

That’s right, Joe. And that greatly impacts the economics with the Generation 6 frac and improved production on that. So, like Ryan said, we’re really encouraged.

Ryan London

Actually I’d say some of our more recent wells have actually did below the $6 million range. In our western acreage, you may recall we have been estimating $6 million to $7 million for drilling complete cost and here recently in the last several quarters; we did below that $6 million several times. So, we’re definitely pointing towards the low end of that range for the wells in the west.

Operator

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

Neal Dingmann - SunTrust

Good morning guys, good quarter. Joe, obviously in the -- for Joe, because you were guys, you continue to get these Eagle Ford cost down, just remarkably low cost, the drilling days I think you mentioned, you’ve been getting some wells done down as low as 8 days. What are you guys budgeting I guess for, on both of those fonts, so on just well cost for the Eagle Ford for the remainder of this year and just sort of total time on those?

Ryan London

I can answer that question again. This is Ryan. What we forecasted for this year and actually beyond this year, like I said, it’s 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. But those are kind of generic numbers. All of our forecasts for cost are very specific to the location, to the lateral length, to the depth, and we take all those factors in account when we’re generating our capital forecast.

But I think on average those are the types of numbers we’re looking at. We’re 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 cost by over $300,000 per well on our first four well pad in the Eagle Ford by using the batch pad drilling in the walking rig. We are forecasting that we’re 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.

Neal Dingmann - SunTrust

Alright. Thank you all.

Joe Foran

Thanks Neal.

Operator

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

Ben Wyatt - Stephens

Hey, good morning guys.

David Lancaster

Hi Ben.

Joe Foran

Hi Ben.

Ben Wyatt - Stephens

Just one quick one, can you guys just remind us on kind of how lease expirations look like out in the Permian?

Joe Foran

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 are state, they have five years and if they are federal, they have 10 years. We don’t have any expirations that are coming up in the near-term in 2014. Really, first ones that we have really in 2015. Is that right, Ryan?

Ryan London

Joe, that’s right. There maybe one or two very small very 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’ve got a pretty good handle on next year as well.

So, it will be sometime before we get down into any kind of a crunch period.

Joe Foran

But the overwhelming majority have 3 years to 10 years or they’re HBP.

Ryan London

That’s correct.

Joe Foran

Does that help, Ben?

Ben Wyatt - Stephens

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

Joe Foran

Ben, you have actually asked a good question and which 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 debt limitation. So you hold all rights, all depth with your well. So it didn’t have the Pugh clauses that you encountered in South Texas. So even if you have a 3,000 foot well, you’ll hold all the deep rights. And generally one well will hold the whole track. Although they are not 3,000 acre tracks, they will hold the 320 of the 640 or whatever size that it is. Ryan, would you add to that?

Ryan London

No Joe, I think you covered it. It’s just 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. And so our intent would be to just as you said, go deeper and make sure that we’re holding all the perspective zones that we’ve identified.

David Lancaster

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

Ben Wyatt - Stephens

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

David Lancaster

Thank you, Ben.

Operator

Thank you. (Operator Instructions). The next question we have comes from the line of Brian Corales from Howard Weil. Please go ahead.

Brian Corales - Howard Weil

Good morning guys.

Joe Foran

Hi Brian.

Brian Corales - Howard Weil

What’s going on the Permian, the Twin Lakes acreage, it looks like that’s kind of the biggest growth area. When -- do you all plan to put the rig up there and test some of that acreage in 2014?

David Nicklin

Yes. It’s David Nicklin here, Brian. And yes, we do. We have a prospect up there; it’s going to be primarily a data well. We are planning a full formation evaluation of the Wolfcamp or what we might call a Pennsylvanian shale in that area. It’s several hundred feet thick out there. And what we plan to do is get a full set of logs and cores through that.

Joe Foran

Brian, I would -- this is Joe again. I would add to you that that’s kind of 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’ve 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 time to do a fairly deliberate methodical, take what we are learning in these other areas and apply that fair. And so that’s going to be done this year. And we are pretty excited about that area. The more we have studied, the more we liked it.

Ryan London

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

Matt Hairford

Brian, this is Matt again; I might just add to that. That’s very consistent with what we have 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 where we got whole core and logs and rotary sidewalls. And so, it’s pretty consistent with what we have done in the past.

Brian Corales - Howard Weil

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

Joe Foran

Now, I mean, your [point] to the group we have not all been of one man on some of this. I think most of our acreage acquisitions have been opportunistic, it’s been a function of kind of how we did it in, what the price is, the length of the term, kind of 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. Ryan?

Ryan London

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

David Lancaster

I might just add, Brian. This is David. I think one reason that we also ended up with a very nice position up in 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 B. And so we’ve been leasing in that area for close to a year now and I think that’s enabled 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 up there in $300 and $400 an acre area.

So and I saw I think that just the fact that we may have decided a little earlier that has enabled us to add to that position a little more aggressively, but as you’ve heard from what Ryan and Joe have said that we still have opportunities in all of the three areas and are looking at, looking the opportunities all the time.

David Nicklin

Can I just add a quick one. Brian it’s David Nicklin here again. I would just like to say this that each of these areas that we’ve highlighted are areas that have, they are 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 it’s there -- that’s what makes this such an exciting play to be and for me as an explorer, there were some great characteristics in all of these areas.

Joe Foran

Brian, anything to add?

Brian Corales - Howard Weil

No. That’s very helpful. I mean because you’ve been able to grow this acreage position pretty impressively. And if I can squeeze one more may be a [tagline] to that. Do you think you can double the acreage from here or are you kind of happy with what you have or is it going to just continue to see what’s available?

David Lancaster

Brian one thing is -- let me just say this, we've 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 depend on what you are willing to pay for it? But you've got to balance that with your ability to drill and your people and your (inaudible) don't want get over your [skis]. We're all in here laugh 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. Since we have let him out, because when he goes out for coffee, he comes back with two deals.

And so, we could. But again how Matador is always gone is we want to be sure that, we're buying quality acreage that we're going to drill in the Eagle Ford very little and in the Haynesville bow very little acreage we have. And we have (inaudible) on this and we didn't validate and turn into wells. And we want to do the same thing in the Delaware and not just buy acreage, but be sure it's part of a coordinated plan and fits into the overall plans for the area. So, yes that we are still seeing plenty of opportunities out there. And we want to get these appraisal wells in and now we're evaluating it. But we want it to be proportionate to our drilling castle and proportionate to our size.

Brian Corales - Howard Weil

Alright. Thanks guys.

David Lancaster

Matt, I think would you?

Matt Hairford

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

Joe Foran

Thank you Brian.

Operator

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

Gab Daoud - Jefferies

Yeah. Good morning guys.

Joe Foran

Hey good morning.

David Lancaster

Hey, Gab.

Gab Daoud - Jefferies

Just going back to the Eagle Ford and specifically generation six frac design, I believe in the release you mentioned 4 [mine] wrench wells drilled have performed pretty well compared to wells drilled on our earlier design, just wondering if you could quantify that or maybe just talk a little bit about the rates between wells drilled on generation six versus generation five?

Ryan London

Gab, this is Ryan again. And I can comment a little on the generation six design, but I think we’re 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 two things on a relative basis due to the variety of lateral lengths and some of the shut-ins that some of the wells experience, it’s real hard to give any clarity on that answer and so we have a little bit longer-term production.

What we can say is that the generation six designs on an equivalent basis if you frac a generation six design next to a 40 acre offset and the generation five design next to 40 acre offset; given the same conditions every time we move to frac generations, the more moderate frac generation has performed better. And I would say that that has remained consistent through the generation six design and across all of our acreage. Does that help to answer the question?

Gab Daoud - Jefferies

Thanks Ryan. No, that’s helpful. And I guess just a follow-up to that. So, is there a particular lease or even an acreage window oil liquids or gas side that you think performed better on a generation six? And then do you see a potential to increase the design from generation six maybe grow up to about 2,500 pounds per lateral foot?

Ryan London

To answer your question on the generation six where we’re going next, absolutely we’ve averaged about 6 months with each frac generation which is about the amount of production data it requires for us to really evolve the frac generation in the right direction. We are working on the generation seven design which we will probably have -- we’ll start sometime this summer and we have expected the generation 7 design is probably going to be more about the fracture geometry in other words our proliferation 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’s going to be more about altering that fracture geometry which would be more appropriate for the 40 acre spacing.

Gab Daoud - Jefferies

Got you, thanks. And then if I could…

Joe Foran

One other thing Ryan is trying to get in.

Ryan London

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, it is somewhere in the Central area and the Eastern area, it’s different rock quality and so we have different designs for all the different areas, it’s 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’s not necessarily consistent drill the acreage because of all of those influences.

Gab Daoud - Jefferies

Got you, very helpful. Thanks Ryan, thanks guys.

Joe Foran

Thanks Gab.

Operator

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

Mike Scialla - Stifel

Good morning, everybody.

Joe Foran

Hey Mike.

Matt Hairford

Hey, Mike.

Mike Scialla - Stifel

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

Matt Hairford

Okay. Brad Robinson, VP of Engineering.

Brad Robinson

Good morning Mike, yes at this point it’s a bit early but we know this area was a good area and expected EUR somewhere in the 400,000 to 500,000 barrel equivalent range. Right now the well is performing better than expected, slightly above or type curve, so we are expecting to probably increase those numbers once we get a little history. But still a bit early to try and do a projection, we have only got a few weeks or month or so of history, but we are expecting numbers to go up.

Joe Foran

Yes. It’s running more than slightly, and its gone two months. So we are optimistic those will increase when we have a little more history, Mike.

Mike Scialla - Stifel

Okay. So both of them you are feeling at this point if they continue to perform the way they are, they are both going to be better than 0.5 million barrel?

Brad Robinson

Yes. I think that’s right. And the other thing that being encouraging to me it’s just been the relative consistency in the production over their early lives. You know the Ranger well, if you look at the curve on it, it’s produced between 400 and 500 barrels a day, just pretty solid alone for a couple of months now.

And you know the Dorothy White it’s settled in probably between 900 and 1,000 BOE per day of which 600 to 650 I’d say oil per day. And again just kind of keeps to rough rocket ride alone between 600 and 700 barrels a day. So, I think that’s the thing that I find the most encouraging is the fact that the wells are just continuing to hang in there and we are not seeing a real sharp decline at all, so that’s real positive I think.

Ryan London

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

David Nicklin

Mike, it’s David Nicklin here. One of the things we had tried to do with both of these wells is that we’ve targeted the laterals not into shales, but into sandstones or fine silkstones. And those I believe that are part of the diversions 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 the shales. So, I think there is a difference in performance characteristics and they are very encouraging.

Brad Robinson

I will add to that, honestly I think that the fact that some of the wells are landed in these sands should not take away that this is, this very 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.

Mike Scialla - Stifel

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

David Lancaster

Yes. 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're going to have a rapidly increasingly GOR in these wells. So for -- we feel pretty good about that right now. So, I think that beginning of the GOR is probably about where we expect it to be maybe even little bit lower. And I think we feel pretty confident that based on looking at the other wells, it will kind of hang in there about where it is.

Mike Scialla - Stifel

Okay, great. If I could sneak one more in, you’re joining kind of Northern part of the Rustler area now, I guess sort of Ranger, I'm sorry where does the rig go after that?

Ryan London

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

Mike Scialla - Stifel

Great. Thanks so much.

Joe Foran

Thanks Mike.

Operator

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

Ann Kohler - Imperial Capital

Great. Good morning gentlemen, just a couple of questions in regard to the Permian. In the conversation you had about your -- the attractiveness of and certainly the desire to add acreage. I think that you have around $30 million year marked 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’s the number that we could see upside too?

Joe Foran

Yes. 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 number so much; it's the quality of the opportunity is that and that's -- it's just too early in the year to predict that is it when we are -- we see quality acreage, we'll try to acquire. And if we don't see the quality acreage, we won't spend the money. So, that's a good question, but probably I should say that per say mid-year.

Ann Kohler - Imperial Capital

Okay. I’ll turn it over and probably going to get this pretty (inaudible) from you, but given that the three wells that you’ve drilled so far obviously you’re very encouraged and are basically performing seems like above your expectations. I mean now that you’ve 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 timeframe at all?

Joe Foran

Well, Ann that’s another very good question is that it’s altered in just the sense that we’re very encouraged and excited and want to go to the fourth rig as soon as appropriate. But we’re 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 and improving drilling times, drill rigs all 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 might want to say your point of view or when you might recommend to us to go to the fourth rig?

Matt Hairford

Yes. Ann this is Matt. And I think what I’d characterize it is, if you think back to 2012 at the time of the IPO where we were in the Eagle Ford it’s kind of the same spot we’re at in the Permian. We had a couple of rigs that we’re just kind of marching across our acreage position [drilling] the different acreage blocks and figuring out what we had and how we wanted to drill. But then I think it’s just exactly where we’re at in the Permian. We’ve got the rig and we’re going to drill few of these wells and figure out what’s good and what’s better, what’s best. And probably this time next year we will be talking about a development plan somewhere 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, we got first and then kind of put a development plan in place.

Joe Foran

Ann there is one another 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 kind of 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 our fourth rig because that’s part of 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 over at on a lot of our acreage. And in most of the instances we are up there in the instead of a 75% net revenue leased, we have 85% or 90% or up. So we have a better net and our marketing guy, Greg [Carnes] has done 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 am saying this is kind of the mid-year decision. We will see how things develop and where we think we can add the most value.

Ann Kohler - Imperial Capital

Great. That was perfect, Joe. And actually that was going to be my next question within 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 kind of guide us to or how we should think of that for the year?

David Lancaster

Hi, and 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 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 occur, not that I anticipate that but that’s what always causes our tax rate to get kind of funny at times. But it was essentially 36% in the fourth quarter and that’s what I would anticipate going forward.

Ann Kohler - Imperial Capital

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

David Lancaster

Yes, ma’am.

Operator

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

Scott Hanold - RBC

Thanks. Just a couple of follow ups here real quickly. Joe, you had mentioned that you have added acreage in kind of those four key areas and just kind of looking to the math that just different areas and acreage positions, it looks like you might be bolting on also in potentially a fifth area. And I know you’ve all talked about being out in the Howard County. Are you picking up more acres over on the Midland side of basin as well?

Joe Foran

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’re 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 still good opportunities there. So I can just say there -- at this time, they are under review. And we like -- we think there are some good areas, but we’re also very pleased with what we have in the Delaware. So that’s hard to say. And I just wouldn’t want to guide people either way on that issue. But it’s under serious review.

Scott Hanold - RBC

Okay. Maybe I could be more specific with my question. If you look at your acreage position and where you’ve identified acreage is about a variance I think of around 5,000 acres somewhere around there on the net basis. Specifically can you say where that is?

Joe Foran

You mean the acreage that we’ve acquired in the Midland Basin, the one that we’ve acquired?

Scott Hanold - RBC

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

David Lancaster

You are saying the 5,000 that we’ve acquired since the first of the year?

Scott Hanold - RBC

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 I guess is what I’ll say. Where is that 5,000?

David Lancaster

Well we have probably 2,000 to 2,500 in the Howard [Dodson] area, gross probably about 1,500 to 2,000 net. There is a -- we actually have a few tracks in Ward County that account for some of that. And we have some tracks in Winkler County that I think that we’ve 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 are going to expire. But that’s down to probably 500 or so acres now, Scott. And I think that makes up the majority of the risk there.

Scott Hanold - RBC

Okay. So, that definitely answers my question. I kind of put the circle on that. 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 floor, 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’ve rammed the activity up there? Is that something where ultimately you’re just going to get an AFE in the mailbox?

Joe Foran

Well Scott, you know us. We’re trying to be proactive with them, we’ve talked to them and met with them and trying to understand what they are trying to accomplish and their timing and to get things firmed. And they are in the process of either having sent some AFEs or saying they are likely to come. But again AFE doesn’t mean the well will get drilled. You don’t know how much of that is they are really serious about until that actually occurs and starts coming about.

So, we’re trying to be very proactive and we’re ready form. If and when we feel that it’s with sufficient assurance, we’ll increase our count. We’ve provided for one and half net wells right now in the Haynesville. And when our well total starts go over one or nears the one and half, we’ll update what we think is the most likely number. But I think we can feel that’s going to go up. And as you’re picking the number, it go from 1.5 to say 3. Will double this year sometime is what appears likely if prices continue to strengthen. And then I think that’s 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?

Scott Hanold - RBC

Yes, absolutely that makes…

Joe Foran

And so until we feel we don’t want to come out there and say we’re going to drill 3 net well or double that and then disappoint you at the end of the year, I think it’s a lot more likely to go up from one and half than not. And I think you can count on some going up; it’s just hard to estimate or to feel that it’s going to happen till you see a little more confidence in the forward curve. David, you’re working on that. Matt, you all are working with them. Is that…

David Lancaster

Yes. I think that’s fine Joe. I think you’ve captured it well and maybe 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’re going to see some activity from them on our property. And as we have more clarity about that, certainly we’ll get more information out about that and how we think it’s going to impact our forecast for the year. It just feels a little premature right now to put something out. And as Joe says, maybe you 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.

Joe Foran

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

David Lancaster

Yes, I think that’s right Joe, in fact is. These are going to -- if they decide to do this and they start proposing wells to it, these are good wells. I mean they are going to be very -- it’s in a very good area. We are in one of the better areas of the Haynesville there and our own drilled area where Chesapeake is likely, may drill some additional wells. And so, I just think that we have -- they are good investments for the company because they are going to be high quality wells, our net revenue interest is very advantageous, Joe has mentioned, our pricing is going to be better than it has been because of the work that Greg has done for us on the marketing side. So, I think there is a lot of early positives about that.

Joe Foran

Yes. And so we have been excited but we just don’t want tell you we are going -- it’s going to happen if we are not sure it’s going to happen.

Scott Hanold - RBC

Okay. No that’s great, I got it. Thanks. And one -- could I clarify two, 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?

David Nicklin

No, you heard that right. So you heard exactly right. So in fact, it’s still producing between 900 and 1,000 Boe per day, quite frankly so it’s doing good Scott.

Scott Hanold - RBC

Okay, that’s great. And if I could flip in one more real quickly here as well. So Eagle Ford, I guess old price realization which obviously are mostly Eagle Ford were down sequential in the quarter, but certainly that trend everybody in the industry is seeing, so not too much to surprise. When you look some of your marketing agreements and arrangements and where pricing is going, can you guide us to what we expect here in the next couple of quarters?

David Lancaster

Greg, you want to try this?

Greg Mitchell

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, of transport and everything. So I don’t really see that changing, we are getting much long contract for the next few years out there. So I don’t foresee that being different going forward.

David Lancaster

Does that answer your question?

Scott Hanold - RBC

Yes.

Operator

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

Irene Haas - Wunderlich Securities

Yes. Hi. This is a bit of a book keeping 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 you are going to drill a Bone Spring well, so that’s well number two and three. Can we have some visibility of where the fourth, fifth, sixth wells going to be?

David Lancaster

Well, I think as we showed you on Analyst Day Irene, the 12 wells are intended to be, there is three wells that we’ve got planned at Rustler Breaks, there are six wells that we have planned in the Ranger area, there is the one, at Twin Lakes that we talked about a little earlier. And there is two additional wells at Dorothy White, excuse me, Wolf, near the Dorothy White.

As Ryan mentioned earlier, the next well is going to be there in Ranger, just as a core of the system, we have one rig in the Eagle Ford but that as we replace it with the walking rig that we’ve mentioned we are 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 have got a second Bone Springs test up in the Ranger area. There will be a couple of additional wells been coming on the Wolf prospect to test the northern and southern ins of that prospect.

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

Ryan London

The different producing horizons in those areas, those are going to be variable too. What we are really trying to test all the different horizons up in the Ranger area, we're going to do as Dave mentioned, we're on the Wolfcamp D now, we will do a second Bone Springs in the future, we’ll do another second Bone Springs and then the third Bone Springs. And in the Rustler Breaks area we’ll be doing a second Bone Springs test and then back to another Wolfcamp test.

So and I think it’s pretty evident what we are trying to do for this year is just test all the different horizons in all the different areas and that’s what you will see at the end of the year and when we are done.

Irene Haas - Wunderlich Securities

Great. Thank you.

David Lancaster

Thanks.

Operator

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

Ben Wyatt - Stephens

Hey guys, thanks for letting me hop back in, a couple of again kind of housekeeping questions. Do you guys are [bidding] what has it; can you tell us how many [PUDs] upon on drilling this year? It's not a follow-up offline.

Matt Hairford

Yes. As far as the exact number Ben, that maybe 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's probably plus or minus 15 is probably pretty good number.

Ben Wyatt - Stephens

Very good. And then one quick one on LOE, you guys I know have given some guidance there. How should we think of that kind of throughout the year? Should it just kind of trend lower overtime or could there be some work over activity throughout the year or something happened in the Permian where we could see some fluctuation quarter-to-quarter?

Joe Foran

Ben, that's a great question. I really appreciate you asking it, because LOE is something we devote a lot of time to around here it's very important to us and sometimes it doesn't get noticed. And Bill McMahon has been working with us for a good while, he has come on Board full time, he is now Vice President and we're just really delighted to have him, because he has done great work down the Eagle Ford with our official lift system, the gas lift 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 be some more challenges, because some of the Bone Springs will produce a little more water.

But let me, 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?

Bill McMahon

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

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

As far as the Permian Basin, we’re just getting started out there. We’re going to have more water handling that we’re doing, but we’re 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’ll see is overtime we’ll start to trim that back to in improvements there. But with the artificial lift are going to be more intense out there, you’ll probably see some more electric submersible pumps moving more fluid.

We have had success, the Ranger 33 as David mentioned has been very good, it’s written flat. That was not a geo-pressured area like the Dorothy White area and that went on gas, but early. But it sat, it’s sitting right around 450 barrels a day, it’s been very consistent. We haven’t really went to lower gas lift [outs] we’re still up high on gas lift out where we’re injecting our gas and so the wells are really strong.

And the advantage out there to get a gas lift and getting it on early is and being able to move fluids out there proves to us that we can use that and do it in other areas out there in West Texas and do it little more economically. A lot of folks go right to [ESP] and that is going to be more expensive, they can’t move volumes. But if can prove, we can do that with gas, we can do it move volumes and move them cheaper.

Ben Wyatt - Stephens

I appreciate it, guys. Thanks again.

Joe Foran

Ben, one another thing I would add is also direct you to companywide look at LOE. If the gas production comes up because it increased activity in the Haynesville, your overall LOE number will come down because the Haynesville gas, it’s going to be $0.20 and it’s dried, 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 Danbury and it’s some that he pays a lot of attention to and has good ideas and has made a difference around here.

Operator

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.

Joe Foran

Thanks Caroline. Thank you all again for your interest, questions, and participation. We appreciate very much you are taking the extra time to visit with us and get this information right. We try very hard to be good stewards around here. And I hope that as you all watched us 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’d urge is that again, we try to make ourselves available to you, if you need 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 as I do, there are some timing differences when you are bringing these new wells on and you’re in new areas, and you are waiting for top line hookups, again, we included the graph in this news release about the six month incremental, since these first six months before we went, and then going public these two years. And I think you begin to see that we deliver on a good path, we’ve got our challenges but I think it’s a really strong group that will address these challenges as they come up and we keep -- trying to keep Matador growing and value and getting to know all of you better too. So thanks very much. I look forward to seeing you all again soon. Bye.

Operator

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

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