Matador Resources Co (MTDR) 2011 Q4 法說會逐字稿

Thank you and good morning. Ladies and gentlemen, welcome to the fourth-quarter and year-end 2011 Matador Resources Company earnings conference call. My name is Francis and I'll be your operator for today. At this time all participants are in a listen-only mode. Later we'll facilitate a question-and-answer session at the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Wade Massad, Executive Vice President Capital Markets. You may proceed.

Thank you and good morning. I'd like to thank everyone for participating in our fourth-quarter and year-end 2011 earnings conference call. I will note that the replay of this conference call will be available through April 12 as discussed and described in our press release.

We have joining us today Joe Foran, Chairman, President and CEO of Matador Resources; David Lancaster, EVP, Chief Operating Officer and Chief Financial Officer; Matt Hairford, EVP Operations; and David Nicklin, Executive Director of Exploration.

Some other presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring our 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 our earnings release.

I would also remind you that certain statements included in this morning's presentation may be forward-looking and reflect our current expectations or forecasts of future events based on the information that is now available. Please refer to the forward-looking disclaimer in our earnings release for more information.

With that disclaimer, let me review our agenda this morning. Joe Foran will provide opening remarks about our overall performance in 2011 and what you can expect from us in 2012. David will then follow up with an overview of selected financial data and operating results in 2011. Then Joe will finish with an operational update for the first quarter of 2012 and we will open the lines for Q&A. I will now turn the call over to Joe.

Thanks, Wade, and good morning to everyone joining us today. It is a pleasure to host our first conference call as a public company to review our 2011 results for what has been a year of transformation and the best year in our operating history. We achieved record production, revenues and cash flow. In addition to these achievements we increased our total proved reserves over 50% and the PV-10 of our reserves over 100%.

The numbers tell the 2011 story. Oil and natural gas revenues almost doubled in 2011 to $67 million from $34 million a year ago. Our production grew 79% to 15.4 billion cubic feet of natural gas equivalent including a fivefold increase in our oil production and our adjusted EBITDA more than doubled to almost $50 million. All in all we think 2011 turned out very well for us.

This brings me to our outlook for 2012. Following the successful completion of our IPO last month, we expect another year of strong growth fueled by our ongoing drilling activity in the Eagle Ford Shale play in South Texas.

We will continue to execute upon our strategy to increase the oil component of our production and reserves and anticipate oil production to make up approximately 35% to 40% of our total production volumes this year and oil revenues to make up approximately 75% to 80% of our total oil and natural gas revenues in 2012. Still I'm very pleased to report that in 2011 our adjusted EBITDA increased 112% to $49.9 million as compared to $23.6 million in 2010.

Finally, before I turn the call over to David Lancaster, our Chief Operating Officer and Chief Financial Officer, I'd also like to reaffirm the 2012 guidance that we released earlier this month. We estimate that our total capital expenditures to be $313 million. We estimate total oil production of 1.4 million to 1.5 million barrels with an estimated exit rate between 5,000 and 5,500 barrels per day.

Finally, we estimate total natural gas production of 12.5 billion to 13.5 billion cubic feet. I would like also to reiterate how excited and pleased we are by these 2011 results and how excited and pleased we are for 2012. And now I'll turn the call over to David Lancaster who will further discuss selected financial and operational highlights. David?

Thank you, Joe, and good morning, everyone. As Joe mentioned, our oil and natural gas revenues were $67 million in 2011, which was an increase of 97% over $34 million reported for 2010. Our total realized revenues, which include the realized gain on derivatives, increased by 88% from $39.3 million reported in 2010 to $74.1 million for 2011.

This increase in oil and natural gas revenues was due primarily to an increase of 79% in total natural gas equivalent production to 15.4 billion cubic feet, which was made up of approximately 154,000 barrels of oil and 14.5 billion cubic feet of natural gas for 2011.

A portion of the increase in oil and natural gas revenues also reflects the fivefold increase in oil production that Joe mentioned as well as a higher average oil price realized in 2011 of $93.80 per barrel compared to $76.39 per barrel for 2010.

Our average production in 2011 was 42.3 million cubic feet of natural gas equivalent per day. That was made up of about 39.8 million cubic feet of natural gas per day and about 422 barrels of oil per day. This compares to natural gas equivalent production of 8.6 billion cubic feet for 2010 made up of approximately 33,000 barrels of oil per day and 8.4 Bcf of natural gas per day.

In 2010 our average production was about -- I'm sorry, those weren't per day, those were total numbers. In 2010 our average production was 23.6 million cubic feet of natural gas per day equivalent, which was made up of about 23 million cubic feet of natural gas per day and just under 100 barrels of oil per day.

Matador's estimated total proved reserves at December 31, 2011 were 193.2 billion cubic feet of natural gas equivalents. This is an increase of 51% over year-end 2010 proved reserves of 128.3 Bcf equivalent.

Of particular note, at year-end 2011 our total proved oil reserves had grown to 3.8 million barrels or about 12% oil by volume versus only 152,000 barrels of oil or just about 1% oil by volume at year-end 2010. This reflects our focus on increasing the oil component of our production and reserves over the past year which, of course, is something we're continuing in 2012.

The PV-10 of our total proved reserves at year-end 2011 was $248.7 million, which was up just more than double from the $119.9 million at year-end 2010.

For the year ended December 31, 2011 Matador reported a net loss of approximately $10.3 million, a loss of $0.25 per Class A common share, and earnings of $0.02 per Class B common share. These results include a full cost ceiling impairment charge of approximately $23 million net of a deferred income tax credit of approximately $12.7 million reported during the first quarter of 2011, and also include total non-cash stock-based compensation expense of approximately $2.4 million.

These results compare to a net income of approximately $6.4 million and earnings of $0.15 per Class A common share and $0.42 per Class B common share reported for 2010. And just as a reminder to everyone, all of our Class B shares converted to Class A shares upon the completion of our IPO.

Now I'd like to discuss our liquidity position briefly. In December of 2011 we amended and restated our senior secured revolving credit agreement which increased the size of our facility from $150 million to $400 million and extended the term until December 2016.

At year-end 2011 our borrowing base was $125 million and we had $113 million of borrowings outstanding. We borrowed an additional $10 million in January and that brought our total borrowings outstanding to $123 million.

Of course we recently completed our IPO and we received net proceeds of approximately $113.6 million. We used the majority of these proceeds to repay the $123 million outstanding under our credit agreement in full and at that time our borrowing base decreased to $100 million. However, on February 28 the borrowing base was again increased to $125 million as a result of a special borrowing base redetermination made by the lenders.

Earlier this week we borrowed $15 million to fund our ongoing capital commitments and our plan is to fund the remainder of our 2012 capital budget with anticipated cash flows from operations and borrowings under our credit agreement and we do plan to seek additional redeterminations of our borrowing base throughout the year.

And finally, let me briefly review our fourth-quarter 2011 performance. Our EBITDA increased 91% on a year-over-year basis from $6.5 million in the fourth quarter of 2010 to $12.4 million in the fourth quarter of 2011. We produced 3.8 Bcf equivalent in the fourth quarter consisting of approximately 41,000 barrels of oil and 3.6 Bcf of natural gas.

That translates to 41.7 million cubic feet equivalent per day, 39 million cubic feet per day of natural gas and 448 barrels per day of oil. All this compares to production of 2.6 Bcf equivalent including 9,000 barrels of oil and 2.5 Bcf of natural gas in the fourth quarter of 2010. Our oil and natural gas revenues increased 69% to $15 million from $8.9 million in the fourth quarter of 2010.

We reported net income of approximately $3.4 million and earnings of $0.08 per Class A common share and $0.15 per Class B common share for the fourth quarter of 2011 as compared to a net loss of $1 million, a loss of $0.03 per Class A common share and earnings of $0.04 per Class B common share for the fourth quarter of 2010.

During the fourth quarter of 2011 we also recorded approximately $1.5 million in non-cash stock compensation expense attributable primarily to a change in the accounting method used to value our outstanding stock options. And with that I'd like to turn the call back over to Joe to give you an operational update for the first quarter of 2012.

Thank you, David. Before I get into the operational update, it's probably appropriate for me to say a few words about our hedging. We maintain an active hedging program and continue to add to our derivatives positions. Currently we have 1.18 million barrels of oil hedged in 2012 with a weighted average floor of $90.51 and a ceiling of $109.84. This represents approximately 80% of our estimated total oil production for 2012 based on the midpoint of our production guidance.

We have 7.2 billion cubic feet of natural gas hedged in 2012 with a weighted average floor of $4.44 per MMBtu and a ceiling of $5.78 per MMBtu. This represents approximately 55% of our estimated total gas production for 2012, again based on the midpoint of our production guidance.

Now I'd like to turn it -- my comments to the outlook for 2012 and provide a brief operational update, as indicated, for the first quarter. We plan to direct approximately 94%, or $295 million, of our 2012 capital budget to opportunities prospecting for oil and liquids, including the allocation of approximately 84% of our budget or $264 million to opportunities in the Eagle Ford Shale play; we plan to drill 30 gross, 27.6 net wells there in South Texas targeting these oil and liquids in that area.

At year-end we had drilled and completed seven wells in the Eagle Ford Shale play. From January 1 through March 15, 2012 we drilled seven additional Eagle Ford wells, five of which have been completed and recently placed on production. Four of these five wells are located on the Martin Ranch lease in LaSalle County Texas and one well is on the Sickenius lease in Karnes County.

From March 1 through March 15, 2012 the Company averaged oil production in excess of 3,000 barrels per day and natural gas production in excess of 37 million cubic feet per day, or a total natural gas equivalent production in excess of 55 million per day, which is approximately one-third oil by volume.

We are currently running one rig in the western portion of the Eagle Ford play in LaSalle County. In addition to the six wells drilled and placed on production in this area during 2011, four additional wells have been completed and placed on production on the Martin Ranch lease during the first quarter of 2012.

The rig was recently moved from the Martin Ranch to the Northcut lease which is also in LaSalle County. Drilling and completion operations on the first Northcut well have concluded and the well recently started flowing back after frac. A second Northcut well is currently drilling with completion operations anticipated to commence shortly after we have finished drilling.

After this well is drilled we will move the rig to the Glasscock Ranch lease in Zavala County where we plan to drill three wells, an Eagle Ford well, an upper Austin Chalk well, and a lower Austin Chalk well. We plan to keep this rig active in the western counties of the play for the remainder of the year.

We are also running one rig on our acreage in the eastern part of the Eagle Ford play. Our first well in this area, the Lewton #1H in DeWitt County, began producing to sales in December of last year. Since then we have drilled three wells on the Sickenius and Danysh leases and are currently drilling a fourth well on the Pawelek lease all located in Karnes County.

The Sickenius lease was recently completed and had just begun to flow back after frac. We anticipate that the wells on the Danysh and the Pawelek leases will be completed and placed on production during the second quarter of 2012. Our current plans are to run one rig continuously also in the eastern part of the Eagle Ford play throughout 2012.

Finally a word regarding the Haynesville Shale in North Louisiana. In 2011 we averaged about 32.3 million cubic feet of natural gas per day in the Haynesville. We ended the year at essentially the same production of which approximately one-third was operated and two-thirds was non-operated.

We do not plan to drill any operated Haynesville wells this year, but have budgeted approximately $13 million for our anticipated participation in approximately 1.5 net non-operated wells. During the first quarter of 2012 we agreed to participate in seven gross, 0.2 net wells in the Haynesville Shale which is consistent with our expectations.

With that I will turn the call over to the operator and we'll now take some of your questions. Operator?

(Operator Instructions). Scott Hanold, RBC Capital Markets.

Could you give a little bit of color on some of your recent Eagle Ford wells that you've drilled and completed? Kind of what type of like [raw] support activity you're seeing from those compared to some of your initial ones? Have -- obviously it's been a little bit more oily, but can you give a little bit more details around that?

Scott, that's a really good question, but I'm going to let David address that. We want to give our guidance to -- annual guidance rather than trying to go through individual wells. Certainly as we get more data points we'll be happy to provide those to you and to the other investors. David, would you add to that?

I don't know that I'd add that much to it, Joe. I think, Scott, that we'll be more prepared to discuss our -- the results from these wells and a little more detail in our first-quarter conference call. For now I think everything is moving along just fine. We feel like that we're in line with where we thought we would be and I think that's about all we had planned to talk about with regard to the new drilling today.

Yes, Scott, we're pleased on this, but want to -- again, when we come out with information -- make it more useful and thorough and we really plan to address that in our first-quarter conference call.

Okay, okay, no, I appreciate that. So we should expect to have a little bit more longer-term data at that point (inaudible) okay?

Yes.

All right, so then moving I guess to my second question then, and you're drilling in the Northcut area right now. Can you kind of give me a sense of your expectations in terms of like oil mix relative to sort of the Martin Ranch that you're seeing there?

And then as you move up that rig to the Glasscock area, you're going to -- it sounds like you're going to knock out the three wells up there that you're going to test. And conceptually kind of give us a view of kind of what you're all hoping to see up there as well?

Let me try to take those in parts. Up there on the Zavala obviously, Scott, is that people have been eager to know what our thoughts are there and there has been some skepticism on that area primarily due to efforts in the western part of Zavala County.

We're very positive on that acreage and think it has multi-pay opportunities and that's what we're going to plan to do is go up there and test that. And I think that area could be a catalyst for us because, as we indicated with you and throughout the road show, that we were very positive on that from the Austin Chalk exploitation potential as well as the Eagle Ford Shale and we're eager to get a rig in there and validate the potential of that lease.

As to the Northcut, I'm going to turn it to David and see if he would either add to the -- my Zavala comments and then address the Northcut.

No, I think you covered Zavala just fine, Joe. I think, Scott, with regard to the Northcut area, I think our expectations are that it's going to be similar to the kinds of results that we've seen at Martin Ranch. It may be a little gassier over in that area -- not sure though.

This is the first well we've drilled on it. We've just got the well fracked and I think we're just starting to flow it back today. So it's probably a little early to give you a lot of information, but that was more or less our expectation going into it.

Okay, I appreciate that and I'll jump back into queue to get my other ones answered. Thanks.

Brian Corales, Howard Weil.

It seems like you're not having any trouble getting wells completed in the Eagle Ford. Do you all have a full-time crew or do you all have set dates? Where does that stand?

Matt is our EVP for Head of Operations. Matt, I'm going to call upon you to give the particulars.

Okay. Good morning, Brian. In answer to that question, what we've got is a contract that's a few weeks from expiring with one of the service providers to follow one of the rigs. We're currently negotiating -- renegotiating that contract along with some of the other service companies.

So what we intend to do is put together relatively short-term contract pricing with those crews. So typically we'll have -- we'll either use one service provider or two to complete our wells and they will be under some sort of a short-term contract.

Yes, Matt, why don't you --?

As far as having -- finding dates or profits or anything like that, we haven't had any difficulty whatsoever thus far.

Okay, no, that's helpful. And regarding the borrowing base, I mean obviously you're spending most of your capital in the Eagle Ford. Can you all maybe make a guess on where you think the borrowing base will be call it at year-end?

Brian, before I get to that I'd like to say one last follow-up on Matt's deal is that -- as these service contracts for the completion are being renegotiated, the pricing trends are definitely in our favor and they're getting better. And the quality of the work we feel is also improved. So costs are coming down and the efficiency is coming down, so it's -- that looks good. As to the borrowing base, I'm going to let David address that. David?

Okay, Joe. Brian, I think the way I would answer your question is I don't think I want to give an actual number of where we think it would be since I don't exactly know where the banks are going to be with their analysis, but I do think we feel it will be more than sufficient to cover our needs for 2012.

Okay. But it probably is going to get reset higher, is that just a --?

Oh, yes, sure, yes. It's just reset to $125 million and we have a scheduled redetermination in May, a scheduled redetermination in November and we also have the ability to request one additional special redetermination in 2012 if we need it. And yes, we anticipate it will move higher throughout the year.

Okay, no, no, that's helpful. Thanks, guys.

Eli Kantor, Jefferies.

What kind of profit mix are you guys using to frac your Eagle Ford wells right now, is it white sand, ceramics or some kind of combination of the two?

Matt?

Eli, what we're using right now, most of the wells that we're completing on the west side are 10,000 foot or less TBD, so we're running white sand on all those wells. On the east side we've got some wells that are in those same similar depths which we are using white sand on.

When we get farther east and deeper in the trend we're not going to be near as comfortable with white sand at this point. I know there are some other operators that are pumping white sand at those depths, but when we get down in the 12,000 foot range, something like that, we'll be running a higher [stream profit].

Okay, thanks. That's helpful. In the press release it looks like you guys provided average production for the first two weeks of March. Do you have what production was in January and February this year?

I think we'll -- this is David. I think that, again, that's something that we'll just -- we plan to just release when we do our first-quarter earnings announcement. As you might imagine given the fact that we were putting a number of wells online, getting our production facilities up and in place, occasionally have a well here or there that might have been shut in while we did a frac on a neighbor.

There's some variability to that. And I think it would probably just be best if we delivered those numbers once they're all finished and we can talk about them in May.

But, Eli, the other thing you can take, the simple trend is that we began the year with about 1,500 to 1,800 barrels a day, we're over 3,000. So again, the trend line is favorable and in our first-quarter earnings call we'll be able to provide more detail on exactly how we're doing.

Okay, thanks. That's helpful. Last question for me is on your reserve bookings, how many Eagle Ford PUDs did you guys have booked at the end of 2011? And what kind of EUR did Netherland Sewell ascribe to your PDPs and your PUDs there?

I believe I'm correct that we had four -- we had six, excuse me, six PUDs that were booked in the Eagle Ford at the end of 2011. And generally speaking, the -- not all had the same EURs assigned to them, but they tended to be in the range of 375,000 to 400,000 barrels of oil and they were all at 1,000 GOR, so the same amount of gas.

Okay, great. Thanks, guys.

Mike Scialla, Stifel Nicolaus.

Glad to hear you're getting the upper hand with some service providers in terms of negotiations. Can you talk about -- I know it varies from area to area, but just some general well costs on those most recent wells that you completed?

Yes, Mike, we can do that. I mean what we've seen really in the last few months, and a lot of it is primarily on the completion side, which really there are two components to a reduction in cost. And one of those is of course the service provider cost. And the other, Joe mentioned earlier were efficiencies that we're seeing by more stages per day and getting things done in a quicker fashion.

So kind of what we've gone to on the Eagle Ford west, we're probably looking at subsequent well costs, in other words second, third wells on an acreage block, but we're probably between $7 million and $8 million.

And on the east side -- it's kind of the same thing at the same similar depths. But as I mentioned earlier, when we get to those deeper wells -- and some of them could require a third string of pipe -- we would probably be looking at an additional $2 million to $3 million possibly on those wells.

Okay, that's lower than what you were before I believe, so that sounds good. Wondering too if you think at this point any of your acreage may be perspective for the oil window of the Pearsall.

I'm going to have David Nicklin -- but the other thing I would note is on the -- many of these wells that we've been drilling, Mike, have been the first well which included certain infrastructure costs, your frac pit, your roads and the like and data, because we've done more coring, more logging on the first wells to get additional data.

So once we get through that first well, the second well many of these leases will come down less than the number that Matt gave you. Is that right, Matt?

Yes, that's right. Those initial costs are pretty substantial. Due to the water well costs they can be upwards of $500,000 just for a water well, building roads, building pipeline, things like that. So the $7 million to $8 million number I gave you was a subsequent well cost.

Right, that makes sense.

Mike, it's David Nicklin here. We're very anchorage by some of the early results that are coming in from some of the regional wells in the Pearsall. But with regards to any details, we are still conducting our studies.

But we're optimistic that as you go towards the north -- northern part of the trend the Pearsall will beginning shallower. And we do think that that's a good lead for black oil and certainly high volumes of NGLs too. But we are -- our studies are still underway on this and we'll be providing some clearer guidance on that later on in the year I think.

But it would be, Dave, when you say the Northern parts of our acreage, maybe Zavala acreage in the Martin Ranch area, maybe a little bit of Northcut that would tend to be in what seems to be what the industry thinks is going to be the oil window of the play?

Absolutely. I think the Martin and Northcut particularly are good because there are some successful wells fairly close by in that area. So we're very encouraged there. But I'm also very encouraged from the Zavala standpoint because as you go higher up on the structure towards the Zavala acreage, that's a particular area where I'm encouraged. But it will depend on the rock fascias and the distribution of the reservoir properties too.

Okay, I'll get back in the queue. But does it -- it doesn't sound like you have any plans to test it yourself this year or are you just going to kind of watch?

Yes, at the moment we don't have any plans, but we are watching it very, very closely.

Thanks.

Dan Morrison, Global Hunter.

Just a quick one. On your chalk test in Zavala County, what are your completion plans there? Is it just kind of the standard chalk completion or is it a little different?

Dan, this is Matt. On our Austin Chalk, our upper Austin Chalk, it will be more kind of the old '90s standard open hole type completion on that Austin Chalk well. As we move down in the section towards the lower Austin Chalk we're contemplating a similar design to what we're using on the Eagle Ford wells where we're fracking every 300 feet, in a stage of 300 feet or so.

Okay. Have you all seen any other staged fracs in the chalk in that neighborhood or at all?

In that particular neighborhood we haven't seen any. We have seen some of the -- what we refer to as [Chalkalford], we have seen some of those wells done in nearby areas. But as far as any frac jobs done on those, we haven't seen a lot of that.

Great, thank you.

[James Howard], HMJ Trust.

They stole one of my questions on cost, but I've got a couple others. Could you address your takeaway capacity for both oil and gas down particularly in the Eagle Ford? Also what you envision for drillable locations coming up, and any ideas you have about future lease acquisition? I got my three questions into one.

Well, addressing the first is the takeaway capacity is that that situation is getting better. I would say it's tight in places and challenging, but there is a lot of pipe being laid. And so that's why I'd kind of characterize that. It's probably -- we're watching that. Probably the other services I think are -- we would describe as readily available, no problems. The pipe we're having to watch pretty closely.

Now your second question, Bo, was what?

Let me ask real quick; do you anticipate that that may affect pricing? In other words, can we get something closer to the LLS posting versus the WTI posting as more pipe is laid?

Bo, this is Matt. In recent contracts that we've put together, we have been realizing the LLS pricing, so that -- in addition to that, some of the oil pipelines that are coming into the area, those will also be at LLS pricing.

Okay. Just quickly, Joe, your vision of drilling -- drillable locations on a go-forward basis and your lease acquisition, any new lease acquisition you might be thinking of?

Right. On the drillable locations, again, as we said in our S-1, we thought we had seven to eight years of inventory based on 120 acre spacing. Recently some of the operators have indicated they're downsizing those units from 120 to 80 acres. We haven't done so. But if you do so that would add about 50%.

As to your second question, as you know us, we're always out there working on acquiring additional leases and opportunities and that we expect to address those in a later conference call as those come together more. But we're actively working, I can assure you, to add to our position.

That's really (multiple speakers) my question, I just didn't phrase it right. Thank you, Joe.

Stephen Shepherd, Simmons & Company.

Just following up on the last caller. Differential guidance for '12, you were talking about how you make get some LLS uplift from some of your crude pricing. From kind of a general corporate level how should I think about Oil & Gas differentials in '12?

On the oil, the pricing we currently have in place with the LLS spread, we're looking at I guess probably somewhere between $6 and $9 or $10 bump to the NYMEX calendar month.

Okay.

And the gas -- you know we're a two stream company, so what we're doing on the gas is rolling the NGL component in. And what we've been seeing there is somewhere -- oh, a $2 to $4 bump in the gas price, which gets us to a somewhere between flat and $2 to NYMEX, something like that.

Okay, that's helpful. And just one more. Regarding down spacing, I think you guys in the past had talked about maybe doing some 80 acre pilots. Any update on that, any commentary or color you can provide there?

We're still planning to do some 80 acre pilot. We don't have any scheduled at this time. We're that new in the development of our acreage that we're not to that point yet. But ultimately we will. But we're so early getting to our acreage that it just hasn't been -- we haven't had the opportunity to do that yet.

All right, that's all I got. Thank you.

(Operator Instructions). Scott Hanold, RBC Capital Markets.

Having to needle into the commodity pricing a little bit more. So on -- so the wet gas volumes, can you talk about where you are in contract? So it doesn't look like -- I'm sorry, in the fourth quarter obviously you didn't really have any in place. But have you ramped up volumes enough where you're able to take advantage of some of the processing upside in those volumes that you have like contracts in place or when should we think about that's actually going to start to take effect?

The contracts, Scott, that we actually have in place now are a percentage of proceeds and a processing fee on the gas. So that's what we have in place right now. I'm not sure that that answers your question.

Yes, effectively I guess I was asking have you ramped up your volumes enough in areas where you have those wet gas to take advantage. Because I think one of the things that you did mention when you were doing your road show is that you needed to scale up your volumes to certain levels in various areas.

Yes, we're real close there, Scott. As Joe mentioned, some of the pipeline constraints there are getting as right there at that level where we're able to realize some of that gain. As we move forward and as the infrastructure improves we'll certainly be able to capitalize more on that.

Scott, this is David. I'm not sure we're going to see a lot of that uplift in the first quarter, we'll see some. But it will probably get better as the year goes on.

Okay, that's great. And then upwards of maybe $2 plus NYMEX best case there, is that right?

Yes.

And then for oil, I just want to make sure I understood. You mentioned that you could potentially see $6 to $7 on a total corporate-wide above WTI. Did I mishear that or is that correct?

It's above the NYMEX calendar month, Scott, so that includes all our transportation and the role and everything like that. So that's an all in price for us.

So your average price on oil would be plus $6 to NYMEX from (inaudible), okay.

And that's where we're producing the vast majority of our oil, Scott. We've got other contracts in place in some of the areas where we're not producing much oil that aren't that same. But we are working more and more towards those type of contracts. So the vast majority of our oil production is subject to those type of pricing.

Okay, great. And then one last thing. On LOE costs and DD&A rates, your LOE costs came down really nicely in the fourth quarter, that was some of this Eagle Ford production coming on. When do you think that LOE may start to creep up because obviously if you have to get pumps in there at some point -- is that more of a 2013 event versus 2012?

This is David. I think that we'll begin to see it, Scott, in the -- throughout the year. I mean, we have certainly modeled ourselves increased LOE costs. These wells are so new that I don't really have a good number to give you this morning and I think that will improve as the year goes on. But our expectation is that the costs are going to creep up on us relative to the operating costs in the Haynesville, of course.

Okay, understood. Thanks, guys.

At this time, gentlemen, we're approaching a quarter till the top of the hour. We have two questions remaining. Eli Kantor, Jefferies.

Could you guys talk about what kind of results you saw from the first Meade Peak test and whether or not you plan on spudding a second assessment well?

The immediate plan would be to drill a 2,500 foot lateral on the existing test that we've done there. So we've been encouraged enough to think in terms of doing that. The biggest impediment to that play right now is simply the gas price.

Yes, just maybe to elaborate just a little bit, Eli, the vertical well that we drilled, we drilled to take a core, collect a big suite of logs, get a lot of data out of it. We haven't actually completed the well. So what Joe is referring to there is kind of our current thoughts as to what we might do, that of course depends on our discussions with our partner as to what we think is the best way to go there.

And that lateral is planned for this year?

If we do it most likely, yes.

Okay, thanks.

Mike Scialla, Stifel Nicolaus.

I think you guys gave it on a yearly basis, I can probably back into it, and maybe you gave it on a quarterly basis and I just missed it. But do you have the realized oil and gas prices for the fourth quarter?

Yes, I can give you those. The realized oil price for the fourth quarter was $96.77, and the realized gas price was $3.06 and that's prior to any hedging impact. So, on an Mcfe basis it was $3.90, but again that doesn't include any hedging impact there. And I guess that our hedging in the fourth quarter added about -- probably about $0.75 or $0.80.

Appreciate it. And then just one last one. Matt talked a little bit about the completion style, I wanted to follow up on that. I know some operators are talking about using larger grain size now and kind of trending away from slick water to using more gel. Are you seeing the same or are you doing something different?

No, we're still pumping the 30/50 mesh sand and what we've kind of gone to is using the fluids we need to get the sand in place. So we've actually cut our gel loading down on some of these frac jobs to the point where we need to go cross link. And at that point we're also trying to keep our fluid loading as minimal as possible. As far as changing any of the grain size, we really haven't done much of that.

Sounds like you were already kind of using a little bit larger grain size than maybe some started with and maybe a little bit more gel than some started with, if I'm reading you right?

Yes, I think that's right, Mike.

Yes.

Okay. Thank you, guys.

And thank you, ladies and gentlemen. This ends the Q&A portion of this morning's conference call. I'd like to turn the call over to management for any closing remarks.

I appreciate each of you that were on the call, I appreciate the questions that you had and, again, thought that they were astute and thoughtful. And again, we've appreciated your all's research and support and this has been an interesting experience.

And we feel good about last year and we feel good about 2012. And we look forward to visiting with you all again and getting to see you in person and to keep the direction of Matador going as it is. So thanks a lot and appreciate your insights and hope to see you all soon.

Thank you. And, ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may disconnect and have a wonderful day.