Good morning, ladies and gentlemen. Welcome to the fourth quarter and full year 2012 Matador Resources Company Earnings Conference Call. My name is Lisa and I'll be your operator for today. At this time, all participants are in a listen only mode. We will facilitate the question-and-answer session at the end of the conference. As a reminder, this conference is being recorded for replay purposes, and the replay will be available through Thursday, 28 of March, 2013, 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. Please refer to the forward-looking statements in the Company's earnings release for more information. I'd now like to turn the call over to your host, Mr. Joe Foran, Chairman, President, and CEO. Please proceed. Thank you.

Thank you, Lisa, and good morning to everyone. First, thanks to all of you for participating in our fourth quarter and full-year 2012 earnings conference call. Second, I would like to introduce those from Matador joining me this morning on the call. We have in the room, David Lancaster, Chief Operating Officer; Matt Hairford, Head of Operations; David Nicklin, Executive Director of Exploration; Ryan London, Vice President and General Manager; and Brad Robinson, Vice President of Reservoir Engineering. Today is about a year and a month since we went public and we are very pleased obviously with our 2012 operating and financial results, our fourth quarter 2012 performance, and how we continued this progress through the first 60 days of 2013. Our staff and Board have done an excellent job finding ways to drill better wells for less money. In 2012, we grew our production eight-fold to just over 1.2 million barrels from just 154,000 barrels in 2011 and 33,000 barrels in 2010. Sequentially, we increased oil production over 40% from approximately 303,000 barrels in the third quarter of 2012 to approximately 426,000 barrels in the fourth quarter of 2012. This growth is continuing in the first quarter of 2013 despite having approximately 10% of our wells shut in at any given time. Matador had record adjusted EBITDA of $115.9 million for the year ended December 31, 2012, a year-over-year increase of 132%, from $49.9 million reported for the year ended December 31, 2011, and slightly above the top end of our 2012 guidance range. Sequentially, we had adjusted EBITDA of $38 million for the fourth quarter of 2012, a sequential quarterly increase of 33%, from $28.6 million reported in the third quarter of 2012 and a three-fold year-over-year increase from $12.4 million reported for the fourth quarter of 2011. I'm also pleased to announce the stronger year-end well performances continued into the first 60 days of 2013. Since the first of the year, we have averaged approximately 5,000 barrels of oil per day and 34 million cubic feet of natural gas per day compared to production guidance of approximately 4,000 barrels per day and 31 million of natural gas per day as announced at Analyst Day on December 6, 2012. With that, we'd go to questions and turn the call back over to Lisa and take some of your questions.

Certainly. Thank you very much. So, ladies and gentlemen, due to time constraints, we ask that you please limit yourself to one question and one follow-up. (Operator Instructions) Again, we ask you to please limit yourself to one question and a follow-up until all had a chance to ask a question. So your first question is from the line of Cory Markling from RBC Capital Markets. Please go ahead, your line is open.

I'll start with the Eagle Ford, sounds like (indiscernible) are drilling on multi-well pads, how much of the 2013 Eagle Ford drilling program will be on multi-well pad this year?

The 2013 program, we're starting off, we've got two pad drilling operations going right now, one on (indiscernible), one on (indiscernible), there are three wells on each of those pads. As we go through the year, depending on how the schedule unfolds, we'll use pad drilling whenever and wherever we can.

Okay. And the Permian, can you guys provide a little bit update on that, and maybe what formations you're going to be targeting going forward?

Yes. David Nicklin?

We are on track to drill three wells this year. We will be focusing primarily on the Wolfcamp but also on the Bone Spring. They will be our main formations and we're focusing there because we are encouraged by a number of well results from around our lease areas. I don't know Brad, if you want to add anything about some of the surrounding wells.

Sure Dave. There have been some recent activity around our Wolf well, our Wolf acreage. [Archies] (ph) just drilled their Reagan-McElvain well which had an initial potential of almost 600 barrels per day with over 2 million cubic feet of gas and they had 18,000 barrels in the first month, so that's an average of about 600 barrels a day. And then Energen has drilled their well also offsetting our Wolf acreage with an initial potential of about 800 barrels a day with over 7 million cubic feet of gas. So, we are very encouraged by those nearby wells and of course the big well everybody talks about up in our Ranger acreage is the Concho Stratojet well which is about two miles from some of our acreage. That well has made 300,000 barrels of oil in the first year. So, again, we're very encouraged by some of those results, and those – the Stratojet is in the 2nd Bone Spring, which will be our target.

Our next question is from the line of Brian Corales of Howard and Weil. Please go ahead.

Can you maybe talk about, so far this year production has been pretty strong, can you talk about what the cause is, did you add more wells than you planned, not had to take many off, or had the well performance better than originally estimated?

Brian, I'm going to ask David to take the call but it's primarily well performance. David?

Hi, Brian, this is David Lancaster. Yes, I would say that it's primarily well performance, Brian. In the last three months, December, January, February, we drilled a number of wells that have just come in and been better than our expectations. I think that a lot of that is a result of the improvements we've made in our fracture treatment designs and really it has nothing to do with the additional wells being put on or wells coming on any sooner. I think that's all pretty well on track for the quarter but the production of the wells has not only come on a little stronger but we've been encouraged to hang in there a little better relative to some wells that we drilled previously.

Brian, I would add, this is Joe, I would add too. There's been a team performance because I would also say that it's been helped by this restricted choke that we've done, artificial lifts on those wells that have gone to artificial lift, and Ryan is in what he calls his fourth-generation frac design in closer perf clusters and more fluid and it seems to break up the rock better and lead to more stimulated rock volume. Ryan, would you add to that?

That pretty much characterizes the design changes and there's been a side-by-side comparison when we've gone into areas where we drilled wells with what we call our generation-two design and compared those with the more recent wells of the generation-four design. We've had improvements in every case, and in some cases as high as 100% improvement.

On that same note, is it too early to – I mean are you all considering even increasing EUR?

I guess the way I would describe it, Brian, there's been improvement on productivity, that's what we can clearly see, 50% or more, but I wouldn't go out there and say EURs until we have more data to confirm that.

Understood.

But clearly, we have enough data to see a 50% more increase in productivity.

Joe, if I can just ask one more, a lot of your neighbors in both the East and the West have been testing downspacing or drilling, or in tighter spacing, can you maybe comment on where you stand from that standpoint if you're testing it or if you plan to in 2013?

Yes. David Lancaster?

Yes, Brian, thank you. We do in fact see what you see, which is that a number of the other operators are testing it, have been through spacings, and we also are planning to do that. In fact, we have a couple of 40 acre downspacing test plan here just in the very near term. So, we're looking forward to doing those and we're excited to see what the results from them may be. I think we feel like that particularly on the western side of our acreage, but also in the eastern side, particularly in the more northern part in the Karnes and the very southern Wilson County that we will have the ability to go to 40 acre spacing and we're excited about the opportunity to test that out and see how it works.

And Brian, I would just add, that would, if successful, that would increase the number of locations that we presently have that we rated Tier 1. Presently we have 275 locations, 155 already Tier 1 and 119 Tier 2, and these are all engineered locations with specific proration units. The 155 Tier 1 are expected to have EURs at 225,000 barrels of oil or better and the 119 Tier 2 would be expected to have 150,000 barrels of oil. And again, these are barrels of oil, not BOE. The Tier 1 would have a better than 20% or 25% rate of return and the Tier 2s would have better than 10% to 15% rate of return.

Thank you very much for your question. Our next question is from the line of Stephen Shepherd from Simmons & Co. Please go ahead. Stephen P. Shepherd - Simmons & Co.: I noticed that the NGL has volumes increased quarter over quarter. Is that a read through for NGLs as a percentage of the total stream increasing in the future, and during the fourth quarter, how much, if any, of your liquids production was NGLs?

Hi, Stephen, this is David. I think what you can sort of read through from the hedging is that we've seen sort of a softening in the NGL pricing and so we've entered into the hedges in order to help us with just our realizations with the price declining. So, I think that's really where we are on the hedges, just as a way of protection, particularly on the ladder ends of the spectrum and particularly of course where ethane is concerned. With regards to the amount of production or what percentage that it is, Matt, do you want to take that question, you probably have a little better handle on that?

Sure. For the year end months, November, December, we had around about 12,000, 15,000 barrels per month NGLs in November, and December was up closer to 22,000, 25,000 barrels per month. It carries on into the first of the year. The one thing that's maybe of interest is that we are per our contract in the conditioning mode for ethane. So, we're rejecting as much ethane as we can at this point, it's more profitable for us to be paid on an Mmbtu basis on the ethane production. Stephen P. Shepherd - Simmons & Co.: That's great, thanks very much, and one more if I can, with regards to the increased well performance, has that been focused into. Tier 1 or the Tier 2 acreage, and maybe asking in a different way, what specific counties are you seeing the better performance in?

Steve, the improved performance is across the board, and as we mentioned earlier, largely related to the improved frac design and the operating practices that we have, the simultaneous fracs, the restricted choke, this frac design that, as Ryan calls it, the generation-four with closer perf clusters, so that's across the board. I think there was a second part to your question. Ryan, would you add to that?

Well, just addressing the first part of the question, I think one of our characterization of improvement comes from the side-by-side comparisons, and that's, like Joe said, that is across the board but there are specific instances where we can point to, to really quantify that improvement, and in some of our newer acreage, of course we don't have older wells to compare with, but we feel like we're getting substantially better wells with the new frac design. Stephen P. Shepherd - Simmons & Co.: Okay, and is there any change to well cost in any of your areas? Analysts say you had given a 7 million figure for the Western Eagle Ford and then 8 million to 9 million for kind of the western part of the East, and then 9 million to 10 million for the rest. Any change in any of those ranges?

I think those ranges are probably still about right. We're seeing some softening in some of the pricing. The rig rates are coming down a little bit, some of the competition for saltwater disposal rates and for different vendors, even steel prices have softened a little bit. So, we are making improvements in those costs and also drilling efficiencies. That may be partially offset by as Ryan continues to evolve his frac design. We're right now currently crossing out frac jobs with these guys right now, and it looks favorable but we may increase fluid volumes, we may do some things to – there will be a constant cost-benefit analysis will be done on each frac job. Stephen P. Shepherd - Simmons & Co.: Thank you for your comments, I appreciate it.

Thank you for your question. Okay, we have one more question in the queue and it's from the line of Gabe Daoud, Sidoti & Co. Please go ahead. Gabriel Daoud - Sidoti & Co.: Most of my questions have been answered already, but I guess just in terms of acquisitions this year, if there's anything specific that you guys could be looking at, maybe some bolt-on acreage in the Eagle Ford or maybe even something additionally in the Permian that you guys are seeing?

Gabe, you're right. We're working on both of those ideas as we speak. We see deals in the pipeline and we're encouraged and optimistic that we will have both some bolt-on acreage in the Eagle Ford and that we will continue to add to our position in the Permian. Gabriel Daoud - Sidoti & Co.: Okay, great. And then, Joe, just one follow-up question. I guess in terms of the Haynesville, what pressures do you need to see for the economics to make sense to get back out there and if they do get, if pressures do get to a point where you would get back out there, would you add another rig to the program or maybe just take a rig from the Eagle Ford and move it to the Haynesville?

Gabe, those are good questions. As to when we would jump back in, that's a combination where processes are and where they're headed and where cost are over there, and you probably want to have a situation where you could hedge your gas to be assured to protect yourself against volatility, but it doesn't take much. Encana announced they were going over there at 350, all of our acreage is HBP, so we don't have to do anything, and we would probably wait a little to a better price, that it starts to get over $4 is where I think our interest level would be., And then as far as taking a rig, we would probably do it with a rig that's over there that's probably where you could make your best deal or hiring a rig over there, but we'd like to a little better price, start to go over $4, and with the trend being more likely to go up (indiscernible). Any of you guys to add to that?

No, I think that's the right characterization.

Thank you for your question. (Operator Instructions) Okay, we do have another question from the line of Bo Howard of HMJ Trust. Please go ahead.

Just a quick pricing question. Are you guys getting priced TI plus or Brent or LLS minus?

What we're getting is the LLS differential. So, it's basically we're the LLS differential less trucking. We have the LLS differential today. Not today, but…

As Matt said, about $10 to $12 more per barrel after trucking, that's after all costs, we get about an uplift of $10 to $12 above WTI.

Excellent, we watch it on our trading thing.

Thank you for your questions. Just to advice you, there are no further questions. So ladies and gentlemen, this concludes the Q&A portion of this morning's conference call. I'd now like to turn the conference back to management for any closing remarks. Thank you.

Thank you, Lisa. I think that this contrast with Lisa and me is the elegance of her accent versus mine, but I appreciate all of you putting up with that contrast, and we appreciate your participation. We're continuing to work and build Matador and grow its worth and value and we appreciate visiting with you and look forward to seeing all of you again soon we hope. Thanks.

Thanks very much, ladies and gentlemen. That concludes today's presentation. You may now disconnect your lines. Have a good day. Thank you.