Matador Resources Co (MTDR) 2012 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the first-quarter 2012 Matador Resources Company earnings conference call. My name is Janada and I’ll 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, this conference is being recorded for replay purposes and the replay will be available through June 4 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 statement in the Company’s earnings release for more information. I would now like to turn the call over to Joe Foran, Chairman, President and CEO. You may proceed.

Thank you, Janada, and good morning to everyone. I want to thank all of you for participating in our first-quarter 2012 earnings conference call. We appreciate your interest in Matador very much. First I would like to introduce everyone from Matador joining me this morning on the call. We have David Lancaster, Executive Vice President, Chief Operating Officer, and Chief Financial Officer; Matt Hairford, Executive Vice President of Operations; David Nicklin, Executive Director of Exploration; and Wade Massad, Executive Vice President of Capital Markets. This morning's agenda is as follows. I will discuss our overall performance in the first quarter of 2012 and express what you can expect from us for the balance of the year. David Lancaster will follow with an overview of selective financial and operational results for the first quarter of 2012 and I will finish with an operational update before we open the lines for question and answer.

The first quarter of 2012 was obviously a very good one for Matador. We produced over 200,000 barrels of oil for the quarter, which is more oil than we produced in 2011 and 2010 combined. We also achieved record total production, record revenues, and record Adjusted EBITDA. In addition to these accomplishments, the PV-10 of our estimated total proved reserves increased 33% during the quarter, due to the continuing execution of our oil and liquids focused strategy, and specifically, our ongoing drilling activities in the Eagle Ford shale play in South Texas. During the first quarter, approximately 27% of our total production volume and 74% of our natural gas revenues were attributable to oil production. This compares to 6% and 27%, respectively, in the fourth quarter of 2011. We continue to execute upon our strategy to increase the oil component of our production and reserves. Our oil production has increased approximately ten-fold year-over-year. This year, we anticipate oil production to make up approximately 35% to 40% of our total production volume and oil revenues to make up approximately 75% to 80% of our total oil and gas revenues.

Before I turn the call over to David Lancaster, our Chief Operating Officer, I’d like to reaffirm our 2012 guidance. We estimate our capital expenditures to be approximately $313 million, 94% of which will be spent on oil and liquids exploration and development. We estimate total oil production of 1.4 million to 1.5 million barrels, with an estimated exit rate of 5,000 to 5,500 barrels per day. Finally, we estimate total natural gas production of 12.5 billion to 13.5 billion cubic feet. With those affirmations, I would like to turn the call over to David Lancaster, our Chief Operating Officer, who will further discuss selected financial and operational highlights. David?

Thanks, Joe. In the first quarter of 2012, we are pleased to report that our Adjusted EBITDA more than doubled to $21.3 million, as compared to $10.1 million in the first quarter 2011. Sequentially, Adjusted EBITDA increased 73% from $12.4 million reported for the three months ended December 31, 2011. Our oil and natural gas revenues for the quarter were $29.2 million. That's an increase of 113% over $13.7 million reported for first quarter 2011. Our total realized revenues, which include the realized gain on derivatives, increased by 107% from $15.5 million reported this quarter to -- I'm sorry, in the first quarter 2011 to $32.2 million for the first quarter of 2012. This increase was primarily due to an increase of 27% in our total natural gas equivalent production to 48.1 million cubic feet per day, and that was made up of approximately 2,200 barrels of oil per day and 34.9 million cubic feet of natural gas per day during the first quarter 2012. That compares to total natural gas equivalent production of 37.8 million cubic feet per day for the first quarter of 2011, which consisted of only 210 barrels of oil per day and approximately 36.5 million cubic feet of natural gas per day.

So a large portion of the increase in our oil and natural gas revenues reflects the ten-fold increase in oil production that Joe mentioned, as well as a higher average oil price of $107.57 per barrel that we realized in first quarter of 2012 compared with $89.11 per barrel for first quarter 2011. Our estimated total proved reserves at March 31, 2012 were 203.1 billion cubic feet of natural gas equivalents and that's an increase of 31% over first quarter 2011 crude reserves of 154.8 billion cubic feet of natural gas equivalents. Of particular note, we want to point out that at March 31, 2012, our total crude oil reserves have grown over seven-fold to 5.7 million barrels or 17% of our total reserves as compared to about 800,000 barrels and only about 3% of our total reserves at March 31, 2011. This reflects, of course, the focus on increasing the oil component of our production and reserves over the last year and that will continue throughout 2012. The PV-10 of our total proved reserves at March 31, 2012 was $329.6 million and that's more than double from $140.6 million at March 31, 2011.

For the quarter ended March 31, 2012, we reported net income of approximately $3.8 million. GAAP earnings of $0.08 per Class A common share and $0.15 per Class B common share. These results compare to a net loss of approximately $27.6 million and a GAAP loss of 65% per Class A common share and 58% -- $0.58 per Class B common share in the first quarter of 2011. And just as a reminder to everyone listening, all of the Class B shares converted to Class A shares upon the completion of our IPO. So we now have only one class of shares outstanding.

Next, I would like to just briefly discuss our liquidity. On February 28, 2012, the borrowing base under our senior secured revolving Credit Agreement was increased to $125 million. That was pursuant to a borrowing base redetermination that we requested and it was based on our December 31, 2011 reserves report. At March 31, 2012 then, the borrowing base was still $125 million, and we had revolving borrowings of $15 million and letters of credit totaling $1.3 million outstanding under the Credit Agreement. Today, we have $30 million in borrowings outstanding under the Credit Agreement and about $94 million available for additional borrowings. We expect to request additional redeterminations to our borrowing base as we increase our proved reserves throughout the year. And we expect to have sufficient increases in our cash flows from operations during the year as well as sufficient increase in our borrowing base to fund our 2012 capital expenditure budget.

Finally I would like to just comment a bit about our hedging program. This really hasn't changed much since our last conference call. We expect to add to our derivatives position throughout the year as conditions warrant, however. For the full year of 2012, we hedged 1.18 million of barrels of oil with the weighted average floor of $90.51 per barrel and a ceiling of $109.84 per barrel. That represents about 81% of our estimated total oil production for 2012 based on the midpoint of our production guidance. And as of the end of first quarter, about 13% of these positions have settled. We hedged at 7.2 billion cubic feet of natural gas for the full year 2012, with a weighted average floor of $4.44 per MMBtu and a ceiling of $5.78 and this represents about 55% of our estimated total gas production for 2012 based on the midpoint of our production guidance, and as of the end of the first quarter, about 25% of these positions had settled.

And with that, I would like to turn the call back over to Joe to give you an operational update.

Thanks, David. As stated earlier, we plan to direct 94% of our 2012 capital budget to oil and liquids opportunities, 84% of which will be dedicated to opportunities in the Eagle Ford. Our plan this year is to drill 30 gross, 27.6 net wells in South Texas, and that program is on schedule. We are currently running one rig in the western portion of the Eagle Ford play. We completed and placed five Eagle Ford wells on production during the first quarter of 2012, including four wells on the Martin Ranch lease and one on the Northcut lease, which are all in LaSalle County. A second well was recently completed and placed on production on the Northcut lease. We recently moved this rig to the Glasscock Ranch lease in southeastern Zavala County just finishing drilling operations on our first Eagle test -- Eagle Ford test well on that lease. Completion of this well is expected sometime in June. We planned to drill two more wells on this acreage in upper Austin Chalk test and a lower Austin Chalk/Eagle Ford test before moving the rig back to the Martin Ranch and Northcut properties. 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 in the eastern portion of the Eagle Ford play. One well was completed and placed on production during the first quarter of 2012 on the Sickenius lease in Karnes County. We also drilled four additional wells on the Danysh and Pawelek leases in Karnes County. The first of these wells was completed and placed on production in April and the other three wells are scheduled for completion during the latter half of this month. We plan to keep this rig active in the eastern counties of play for the remainder of the year. In addition, we have recently participated with EOG Resources in drilling an Eagle Ford well on our joint acreage position in Atascosa County. Completion operations on this well are currently being finalized. Finally, regarding the Haynesville shale play in North Louisiana, I wish to reaffirm we have no plans to drill any operated wells on these leases this year. We did participate in 12 gross, 0.6 net, non-operated wells in the first quarter of 2012. With that, I will turn the call over to the operator and we will now take some of your questions.

(Operator Instructions) Scott Hanold with RBC Capital Markets.

Could you talk a little bit about what you saw in that Zavala well? Obviously, that is kind of an area that can provide some nice upside optionality and you know when you drilled to the Eagle Ford, can you talk about the thickness of it and what you saw up there?

Scott, we were not planning to do any release on that and probably -- until probably the second quarter earnings call. We are going to complete that well in June. And we will see how that goes. At this point,we are encouraged but the proof will be in the results and as we get them we will pass them on to you all, and we are eager to do so.

Okay. Fair enough. And by that time, would have you drilled I guess an Austin Chalk well? Would drilling have been completed by then as well?

Certainly it will be drilled. The completion -- we haven't gotten to. We will drill all three of those wells will be drilled. The first completion, as we said, will be in June. The other two should occur in July. That's the present plans.

Are the proximity of those wells going to be pretty close to each other?

Matt, were you trying to say something?

I was going to say, Scott, we've drilled the first one in [kasted] and we are moving the rig over to drill a second one right now. And they are relatively close to each other. They are all in the same block, of course.

Okay. And then move them over to into the eastern part a little bit up in your Atascosa bridge. It sounds like EOG gotten a little bit active now. Do you anticipate or your conversation with them indicate they are going to do a little more drilling up there or do you know what the plans are?

You know, Scott, we don't know much beyond that this well is being finalized completion and depending on its assess, we will determine what follows. So we will have to see the outcome of this well, I think, before knowing how aggressively they will plan to develop the rest of that acreage.

Are you in active conversations with EOG on this acreage or does it come down to you received an AFP and then [follow up] drill on the well?

Scott, I think you know us well enough to know that we are not very passive.

Okay. That's fair enough. Appreciate that color and one last thing if I could. Could you just give us an update on acquisition activity in both Eagle Ford and potentially the Permian basin?

Scott, we are working on them. And rather than issuing a -- we are trying to avoid issuing a press release every time we pick up 100 acres. But as we put together something of significance -- as we finish putting together something of significance we will, of course, make an announcement. I just don't think it's helpful to come out every couple of weeks with another 100-acre announcement.

Okay. So you are picking up pieces around your blocks but it's not a significant enough chunk at this point. Is that a fair statement?

No. You're -- Scott, I mean really like and respect you, but that's a little too much. We are having some success and I think the numbers as they come out will speak for themselves. We're -- and we will have an announcement as we put the finishing touches on something of -- they will have some significance is I guess is the best way to go. But we are pleased with the way that's going and the opportunities that we are looking at.

Okay. I think I understand what you are saying. I appreciate the time and look forward to that update.

Thanks. We do, too. We look forward to getting that out to you, Scott.

David Amoss with Howard Weil.

Good morning. Joe, can you give us your thinking on when you think you might be able to go back and ask for another redetermination on the borrowing base, you know, post your March 31 reserve update?

I will look to that to doing that in June.

I think what we were -- this is David. I think what we were talking about, David, was we have already been speaking to the banks about it and thought maybe the best timing for us would be to get through our second quarter reserves reports. That would give us a chance to put another half dozen or so wells -- oil wells on the report and everybody just seemed to think that might be the best time to go back and sort of ask for something in maybe early July that's based on our 2000 -- our mid-year reserve numbers.

Okay. Great. Thank you. Then, Joe, can you give us kind of some color on how to think about LOEs going forward? I know you had some extra costs on production facilities in the first quarter. How should we generally view the trend in LOEs in the second quarter and in the future?

Right. David, that's a really good question and I would approach it from this way. Obviously, as you convert to oil from gas, your LOE is going to go up. And what is causing, in the first quarter, is that we had extended flow back from our wells as we are installing permanent production facilities. By that, when you flow them back, that necessitates that these volumes of having 24-hour crews out there and more personnel to handle the kind of volumes that these wells produce. You also do that for safety reasons and that is expensive. Now, as you install permanent production facilities, then you don't have to have those crews around. But, you've got to drill that first well, get it flowed back and so the amount of flow back time will be reduced in the coming periods from say several weeks to maybe five days and then we can turn it into the permanent production facilities. The permanent production facilities also have some costs. They are one time and after that, you gain the economies of scale. Matt Hairford, our Head of Operations, would you add anything to do that?

Joe, I think that's exactly right. In addition to that on a going forward basis, we've elected to build our production facilities at a different site as opposed to on a well site. Going forward, we will be able to get those things done sooner, earlier, and therefore the first well in a new area we'll be able to turn that, like you said, to permanent facilities sooner than later and then when we go back to drill subsequent wells, then we'll already have those facilities in place so that time should be shortened there also.

Okay. On a per unit basis, do you think first quarter would you say is probably close to a peak in LOEs?

David, I can't say that. Part of that depends on how many new wells you're bringing on in a given quarter. So you know we -- certainly the effort is to get those costs down. One other factor that will determine is if you have any workovers. You are going to have some workovers from time to time. It's hard to predict when they are. Kind of like injuries in a football game. If you can go a whole quarter without a workover, your LOEs are going to be much improved. We had about 10% of our LOE costs were attributable to one workover. But I can't say we won't have another workover again this year. I hope we don't have one the second quarter, touch wood. In which case that would improve it. But there is a lot of factors and I just would be hesitant to make a LOE prediction at this time. But as we have a little more history with these wells, we will be able to make a better -- we will be able to provide you with a better estimate. These are some high class problems dealing with these kind of volumes and we are trying to be sure that we are safe as well as building for the long term. Those two things are really guiding our efforts. We want to not just do some that has some short-term savings on LOE but we are really doing something that makes economic sense over the many years these wells will produce and for safety that there is not an accident out there or an environmental event.

Okay. That was very helpful. Thank you very much, guys.

Stephen Shepherd with Simmons.

Good morning. You all have any plans to add to your hedging position out into 13? Are you opportunistic with regard to doing that? What are your thoughts there?

Yes. I think David Lancaster mentioned that as opportunities arose that we would add to our hedging position. So we're -- we give thought that to every time the prices goes up or other opportunities present themselves. So you should expect it.

Okay. Any color on what well costs look like in the Eagle Ford? Can you talk a little bit about that?

The well costs are coming down. It's hard for us, again, to give a lot of precision because we are not drilling a, quote, standard well because the three things that affect well costs are primarily your depth, your length of your lateral, and the kind of profit. So we have a range in the western counties are shallower and as you go to the east, you end up having to set another string of casing at some point. So that is very -- and then the second thing is the length of the laterals. We've drilled laterals -- we will be drilling laterals some as short as 3,500 feet likely to 7,000 feet. So that's been a big difference. And then the profit as you know as you go deeper say 9,000-10,000 feet, you start to look at maybe moving from White Sands to one of the higher strength profits. We haven't come up with a normative what I call standard well. But we can tell you that the costs are coming down. For example, on the frac costs is that we are about to enter into two new service contracts with two of the large frac companies, two of the very largest and the immediate savings is 25% and probably as much as 50% from six months ago. Is that correct, Matt?

Yes, sir. And the efficiencies that we talked about are also additive here. We just did a 15 stage fracking in less than 48 hours. Our rental costs of all of the equipment on location not only -- those things softening somewhat but the availability is a lot greater than it was just a few months ago. The prices were a little better. The efficiencies are continuing to improve. We are continuing to work on those things.

Does that answer your question?

That works. Thank you very much.

All right. Thank you for the question.

(Operator Instructions) Joseph Thorpe with Citigroup.

Good morning, everybody.

Hey, Joe.

Good morning.

Could you -- is there is any chance you could share the IP rates for the wells that completed during the quarter?

Joe, we are not going to do that. We don't think that adds that much. It's not something that if we were buying properties that we would pay that much attention to. We don't see where that's particularly helpful. What is meaningful, I think,is the annual production guidance that we will keep providing and affirming or for you because your IP rates can really vary for how long, how big a choke that you get them on. You can look them up at the railroad commission if you find them useful. We generally don't. What we think is best given the operational sense of it is to keep providing this annual guidance from that and number of wells that we are drilling and you look at the quarterly rates and you can see we are having good results. But to get into a deal with an IP rate that can vary so much over time that I don't think that will be as helpful as providing you guidance on cost, hedging, and production numbers.

Okay. Could you maybe then Joe -- just perhaps -- comment --

Particularly over the longer term.

Right. Okay. Could you maybe then just comment, Joe, on what the -- how the wells have been performing over a longer term basis relative to your tight curves and expectations?

We are very pleased. We feel like we are on schedule. Our costs are less than we would have expected at this time. And we feel like we are gaining ground on continuing to improve the fracs. I would say we are very pleased and on schedule. Certainly meeting expectations would like to look forward from the benefit of a longer period of time. I think we are very happy with the acreage that we have and the program and you know, it's hard not to be -- feel real happy when your production is ten times what it was a year ago.

Yes. You guys have definitely done a great job. Ramping up the oil volumes.

Then you look at it sequentially where we were in September or December versus now. You know, it's really pretty exciting for us.

Yes. Yes, it is. So I know you guys were pretty conservative on your capital cost estimates that you baked into your 2012 budget. And it looks like Q1 CapEx is trending below budget although I know you are probably going to accelerate more throughout the year. But is there any chance, Joe, with the well costs continuing to be below your expectations? Is there any chance for maybe even a reduction in CapEx? Or would you maybe take the incremental dollars and pick up some more acreage in the Eagle Ford or the Permian.

Well, that's certainly a possibility. And that's something we are looking at is that we are not bound exactly to the budget if we had a good acreage opportunity. We would increase it. At the same time, we would make whatever other adjustments. Obviously, the drilling program is meeting our expectations. So we do not plan to reduce it in that area but we certainly could add to the budget if there were appropriate acreage opportunities would present themselves. We should have a little savings and our geologists are here looking every day making suggestions on what to do with it. They would love to have more.

Sure. Okay. Great. Thanks a lot, guys. Good luck next quarter.

All right. Thanks, Joe.

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

I would just like to thank you all again for your interest, your questions, and participating in the call. You know, anyway we look at it, we are really excited. It was a record quarter for us. Maybe one of the best that we've had in Company history. Our oil transition is on schedule working out. Production up ten-fold. Looking at it sequentially, we were very pleased with that gain, too. So, you know, we are hard at work. We look forward to the rest of the year. I think you will continue to see the oil production grow over the year. We hope to continue to achieve some cost savings in key building a company over the long term that will continue to perform as well in the years going ahead as we have done in the years past. Thanks again. We really appreciate your interest and look forward to visiting with you all again soon.

Thank you for your participation in today's conference. This concludes the program.