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Legacy Reserves LP (NASDAQ:LGCY)

Q4 2012 Earnings Conference Call

February 26, 2013, 10:00 AM ET

Executives

Cary D. Brown - Chairman, CEO and President

James Daniel Westcott - EVP, CFO

Paul T. Horne - EVP, COO

Kyle A. McGraw - EVP, CDO and Director

Analysts

John Ragozzino - RBC Capital Markets

Christopher Sighinolfi - UBS

Kevin Smith - Raymond James

Daniel Guffey - Stifel Nicolaus

Michael Peterson - MLV & Company

Abhishek Sinha – Bank of America Merrill Lynch

Praneeth Satish - Wells Fargo Securities

Eric Busslinger - Marret Asset Management

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Legacy Reserves LP Fourth Quarter 2012 Results – Annual 2012 Results and 2013 Guidance Conference Call. At this time, all participants are in a listen-only mode. Following the call, there will be a question-and-answer session. As a remainder, this call is being recorded today, February 26, 2013.

I’ll now turn the call over to Dan Westcott, Legacy’s Chief Financial Officer. Please begin.

James Daniel Westcott

Good morning. I appreciate everybody dialing in for Legacy’s fourth quarter and annual 2012 earnings call. Before we begin, I’d like to remind everybody, during the course of the call, Legacy management will make certain statements concerning the future performance of Legacy and other statements that would be forward-looking statements as defined by Securities Laws.

These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions. Actual results may differ materially from those discussed in these forward-looking statements and you should refer to the additional information contained in Legacy’s latest 10-K which we released on/or about February 27, and subsequent reports as filed with the Securities and Exchange Commission.

For those of you don’t know Legacy, we are an independent oil and gas limited partnership headquartered in Midland, Texas, focused on the acquisition and development of long-lived oil and natural gas properties, primarily in the Permian, Mid-Continent and Rockies regions of the United States.

This morning Cary Brown, Legacy’s Chief Executive Officer and I will provide commentary on the quarter and the year. We will open the call up for Q&A to the entire management.

And I will now turn the call over to Cary.

Cary D. Brown

Thank you, Dan and thanks to our friends and unitholders for joining us today. 2012 was a landmark year for Legacy and close the largest acquisition in our history on December 20th, a $500 million acquisition of Permian properties from Concho. These properties with some of – in some of the most prolific fields of the Permian Basin.

With the exception of Lower Abo, these properties provide us with the strong set of mature PDP assets with modest production decline rates as well as a very strong portfolio of proved and unproved drilling locations and developed non-producing projects. Our integration of this acquisition is going smoothly thus far, and since assuming operations on January 1, our operations group is even more excited about the asset potential they’re seeing.

The Company set a record 2012 improved reserves with 83.2 million barrels. We also set an annual and quarterly production records of over 14,800 barrels per day in 2012 and over 15,700 barrels per day during the fourth quarter. We generated Adjusted EBITDA of $197.6 million, the second highest in our history. We do face some challenges in 2012 with both unusually high well failures and the Midland-to-Cushing differential. The Midland-to-Cushing differential averaged about $3 in 2012. Historically, this has been about a $0.50 number for us. This was hedged – unhedged exposure for us in ’12.

In ’13 we have locked in, if you look at the last three quarters in the year we locked in those numbers instead of the $1.50. We still have a little bit of exposure. We’ve got some hedges for the first quarter, but you will see some exposure that we have in the first quarter differentials. But I’m pleased with how we mitigated that for 2013, that exposure to the differentials.

On the development front, we continue to be pleased with our results from Wolfberry drilling and are excited about the results from our new horizontal Bone Spring well that began producing in November. Due to our strong acquisitions, strong development results and promising outlook, we increased our distribution every quarter in 2012, resulting in year-over-year distribution growth of 3.6%. We’ve now increased our distribution for the last nine consecutive quarters. If you assume $50 million of development capital expenditures as maintenance capital for 2012, our coverage ratio was 1.11 times, that would be about 25% of EBITDA if we were using that number.

If you look at it in the fourth quarter of $30 million of maintenance capital expenses the same way we’d had about a 105 coverage, if you take out the transaction cost of the Concho acquisition and all the one-time expenses relating to the high yield offering and those things, we’d have that 1.12 times coverage for the fourth quarter. So very pleased with where our coverage is coming out.

With a strong drilling results and our newly-expanded development inventory, in January our Board approved our 2013 capital budget of $90 million. We look at that, we consider $68 million of our budget to be maintenance capital. With our multi-year, oilweighted drilling inventory, our recently closed Concho acquisition, our strong ongoing acquisition efforts, really excited about what we look at in 2013. I would be remiss if I didn’t tell you guys a little bit about how pleased I’m with the employees and the people that are at Legacy, they just did a fantastic job of I think close to $600 million of acquisitions last year. We got everybody pulling the same direction and I think we have the best team in the country at buying harvest properties, executing on those and bringing those in. And so it’s a fun time to be an Oil Weighted Company, I think we’re in the most exciting basin in the country right now. The Permian just keeps on giving, you can see that from our Bone Spring wells and then you look at being on the best team in that basin, I’m really excited about what ’13 has to offer and the way God has blessed us.

With that, I’m going to turn over to Dan, to talk a little more in detail about guidance and our numbers.

James Daniel Westcott

Thank you, Cary. As Cary mentioned, we’re really pleased with our acquisition efforts and growth in 2012. To finance the Concho acquisition, we completed our largest equity offering and issued $300 million of senior notes during the fourth quarter. In addition, our now 20-member bank group redetermined our borrowing base at $800 million. And as of February 25th, we had $500 million of debt outstanding under our revolving credit facility, giving us approximately $300 of current availability, which is another Company record for future acquisitions and development projects.

With favorable conditions in the capital markets and ample availability under our credit facility, we look forward to another year of strong results and the pursuit of additional acquisitions. Before discussing the results, please note that the 2013 guidance table that’s contained in our earnings release that we issued yesterday afternoon. This is the first time we’ve provided guidance and we felt it was necessary given to do so, given our landmark acquisition for Concho.

Highlights of our guidance are as follows. We’re estimating our current – our production for 2013 to be approximately 19,150 Boe per day to 19,750 a day. As production from development projects and our $90 million capital project will help offset production declines from our new Lower Abo assets from Concho as well as moderate to low production declines from the remainder of our asset base.

We are estimating our differential to be approximately $7.50 to $9 per barrel in 2013, which we project the materially wider in the first quarter somewhere in the range of $11.75 to $13.50 a barrel, primarily driven by Midland-to-Cushing differentials which have since narrowed materially.

We are estimating our oil and natural gas production expenses, excluding ad val to be approximately $18.30 to $19.20 a barrel. I will also point out in the earnings release our hedging tables. If you look at that and look at the previous quarter we’ve added a considerable amount of hedges primarily attributable to our new Concho assets, which we’re trying to lock in our acquisition economics. With the recent discussions, I guess. the other thing to point out is with recent discussion surrounding the hedging and the MLP space, I think its worth noting that these issues really don’t apply to legacy.

Our hedges have always been costless, we do not do standalone puts and we do not intend to deviate from this policy in the future. You will notice our hedge position disclosure that we’ve added considerable Midland-to-Cushing basis swaps that Cary mentioned earlier, we’ve seen a quite a bit of volatility in that spread from over $20 a barrel in November to about $0.50 last week. And given that about three quarters of our production comes from the Permian, we went ahead and locked in that exposure. For the first quarter we have 2,000 barrels a day hedged at $1.25 and for the remaining three quarters we’ve 8,000 barrels a day hedged at $1.47.

Now for our results. I will make comparisons of annual 2012 results to annual 2011, followed by comparisons of fourth quarter of 2012 results to third quarter 2012. This information has remainders contained in our earnings release and for more detailed disclosure, we encourage everybody to look at our latest 10-K which we expect to file tomorrow.

2012 highlights include a 13% increase in production to 14,811 Boe per day from 13,071 Boe per day in ’11, primarily attributable to the $635 million of acquisitions in producing properties, which includes 12 days of Concho at full-year impact of our ’11 acquisitions and $68 million of development capital in 2012.

Also we had a 31% increase in our yield improved reserve to $83 million Boe. That includes 88% PDP and 68% liquids, which compares to about 53 million barrels at year-end ’11 which was 85% PDP and 68% liquids. This was driven by – this increase is driven by 27 million barrel increase from our acquisitions offset by 5.4 million barrel decrease from production and 2.4 million barrel decrease from lower commodity prices.

Adjusted EBITDA of 197.6, was our second highest in history despite lower realized commodity prices, higher workover and other unusual well failure expenses. Other annual financial and operating results comparing 2012 with 2011 include – and our commodity price realization. By commodity our daily oil production increased 13% due to acquisitions in oil focused development projects. Our gas increased by 17% primarily due to the impact of our acquisitions. And to a lesser extent, production from our 2012 and development activities as the Wolfberry play primarily produces oil, but also a significant amount of casing head natural gas, which is rich in NGLs.

Daily NGL production for the year was flat. Average realized prices excluding commodity derivatives were $63.91 per Boe in 2012 down 9% from $70.61 per Boe in 2011. Oil prices decreased 4% to $85.78 from $89.62. This $3.84 decrease is primarily attributable to an increased weighted average oil differential of $2.75 per barrel as well as slightly lower weighted average WTI crude oil price. The Permian experience a record increase and the Midland-to-Cushing WTI differential which we talked about earlier, it averaged about $3 in 2012 compared to $0.50 in 2011.

Natural gas prices decreased 28% to $4.38 from $6.05 in 2011. As a remainder, we’ve talked about this before, but as a remainder our average realized natural gas prices are favorably impacted by the NGL content in our Permian basin natural gas. Our lower realized natural gas prices reflects $1.21 lower Henry Hub price as well as lower positive differentials from lower NGL prices. So as NGL prices decreased our dry natural gas reported volumes realized price also decreased.

Production expenses excluding ad val increased 18% to $103.4 million from $87.6 million in 2011. Per Boe that have 4% increase to $19.08 from $18.37 in 2011. Production expenses increased primarily because of one, a $5.1 million related increase in workover and other unusual well failure expenses due to both increase in number of incidences as well as average cost per job. And two, production expenses from our acquisitions.

Legacy’s G&A expense excluding LTIP compensation increased $21 million from $19.1 million. This $1.9 million increase stems from a $3.3 million increase from salaries due to the high end of additional personnel with the growth of our asset base partially offset by lower acquisition related cost of $1.3 million in 2012.

Cash settlements received on our commodity derivatives during 2012 were $5.9 million, as the $16.1 million received from natural gas was partially offset by a $10.1 million paid on oil. This $5.9 million in cash settlements received compared to $0.6 million received in 2011.

Development capital expenditures decreased $68.2 million in 2012 from $71.6 million in 2011 as we continued our one rig Wolfberry operated drilling program from most of 2012, drilled to about first new horizontal Bone Spring well in may 2012 and increased our capital workover activity in the Permian, in Wyoming relative to 2011. Our non-operated capital expenditures were 23% of our total in 2012 as compared to 25% in 2011.

Now for the fourth quarter. We posted a 6% increase in production to 15,729 Boe per day from 14,772 Boe per day in the prior quarter primarily due to the Concho acquisition, which provided 640 Boe per day in the quarter. A 4% increase in adjusted EBITDA to $51.6 million from $49.5 million. We posted our ninth consecutive increase in quarterly distributions and in the year of $0.57 per unit, which represents a 3.6% year-over-year growth.

And then as we previously mentioned, we close our largest equity offering in November, gained first time access to the high yield market through our $300 million 8% senior notes offering and increased our borrowing base for the third time in 2012 at $800 million with the newly expanded 20-member bank group.

Other financial and operating results comparing fourth quarter to third included average realized prices, excluding commodity derivatives were $62.51 per Boe in the quarter, up 1% from $61.95 in the third quarter. This was driven by our separate commodities that oil decreased 3% to $80.69 from $83.54, which was really driven by a drop in WTI prices as the – as an increase in the Midland-to-Cushing differential was offset by a significant decrease in our Rockies differential during the quarter. Our natural gas prices increased 15% to $471 from $410 on third quarter and average realized NGL prices increased 15% to $1.05 from $0.91 in the third quarter.

Production expenses, excluding ad val remain flat at $28 million -- $28.3 million and production expenses associated with recent acquisitions were offset by lower workover and other one-time well failures. But we’re still roughly a $1 million higher than normal levels about $1.1 million lower than third quarter. Per Boe our production expenses decreased 6% to $19.59 from $20.76.

Legacy’s G&A excluding LTIP compensation totaled $6 million for the fourth quarter compared to $4.9 million in the third quarter. This increase was attributable to acquisition related and year-end compliance and other costs. Cash settlements received on our commodity derivatives during the fourth quarter were $3.9 million compared $6.1 million received during the third quarter.

The decline in WTI oil prices between September and December resulted in a negative one-month lag effect on our crude oil hedges. With our cash settlements received being approximately $1.4 million lower during the fourth quarter. In contrast, this lag effect caused our cash settlements received on our oil hedges to be approximately $2.7 million higher during the third quarter due to rising oil prices during that period.

Development capital expenditures were relatively flat quarter-over-quarter. Our development capital expenditures in the fourth quarter included our Wolfberry drilling program as well as an operated horizontal Bone Spring well that began producing in November. The results of our Wolfberry drilling program continue to meet or exceed expectations and the results of our horizontal Bone Spring well had clearly exceeded our expectations.

With that, we’ve concluded our prepared remarks. As we mentioned earlier I’d encourage everybody to review our earnings release and read our Risk Factors and other more detailed disclosures in our 10-K which will likely be filed tomorrow. At this time, operator we’d like to open up to Q&A.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from John Ragozzino with RBC Capital Markets. Please go ahead with your question.

John Ragozzino - RBC Capital Markets

Hi. Good morning, gentlemen.

Cary D. Brown

Good morning, John.

John Ragozzino - RBC Capital Markets

Can you just give us a little overview on what the current service cost environment is in the Permian Basin?

Cary D. Brown

Yeah, well Paul, why don’t you talk about that. Paul Horne, our Chief Operating Officer.

Paul T. Horne

Yeah, John I am not sure specifically which service cost because that’s a pretty wide range, I’ll talk in general and then if you have specifics speak up. We’ve actually seen some rig availability come loose through the fourth quarter that has helped us with drilling cost, it helped us as far as curb the increase of completion cost, we haven’t seen completion cost coming down significantly, but we also haven’t seen them increase which – that was pretty steady through the later half of 2011 and the first half of 2012. The drill rig drives so much of our costs pulling units for completions and more workovers. So generally speaking still pretty good about what we’ve seen in the last three to four months. I haven’t seen the increases, but I also don’t want to propose it, we’re seeing or expecting a significant decrease in those costs in 2013.

John Ragozzino - RBC Capital Markets

Okay and this leads into the next question I have. Can you give us a break even price on your Wolfberry projects right now?

Paul T. Horne

No. We’re so far from that number, we haven't done any calculations to give us a feel for when that would be appropriate.

John Ragozzino - RBC Capital Markets

Okay. And you mentioned the Bone Spring well but you didn’t give us very much detail. Do you care to elaborate on some of the specifics in terms of IPs or what kind of type curb you might be using?

Paul T. Horne

Yeah, as you know we’ve avoided press release in IPs. What I’ll tell you is, the well has been flowing for almost four months now. It came on about November last, and it’s continuing to flow today and it appears that on – its current decline rate that the well laid out in approximately six months and that was like $6.5 million investment. So far exceeded our expectations we’re thrilled with the performance of it and we plan on drilling several more of those in 2013.

John Ragozzino - RBC Capital Markets

Okay. And just one more on the prove reserve side, if you guys spent $68 million in 2012 and we kind of exclude revisions, that gives me a finding and development cost of $22.67 a barrel. Is that primarily driven by the fact that you’re just taking barrels from the PUD category and moving to the PDP category or is there something else that I’m missing, and I’m just wondering where the lack of organic growth is on such a large budget?

Paul T. Horne

Great, question John. We’ve looked at that in detail. In 2012, its significantly different from 2011 and prior our – far and away the majority of our capital program was drilling Wolfberry wells, that Wolf PUDs and it was conversion from PUD to PDP. In 2011 when we were drilling Wolfberry wells quite often, we were drilling in areas that we drilled one and proved two or three wells up, but in 2012 we were converting. We had already booked the horizontal well on the lead unit that we drilled the horizontal Bone Spring well and so that was the conversion and although it did prove up a couple of horizontal offsets to it we had vertical PUDs on the books. So it was although we replaced four vertical wells with a horizontal well, again we weren’t adding reserves with the majority of the drilling we did in 2012.

John Ragozzino - RBC Capital Markets

That’s very helpful, and I lied, I just got one more quick one. Do you have any idea that the trend in the non-op CapEx levels should continue and you said over 2011 you have an increased 2012, ’13, ’14, do you expect the similar growth in the percentage of your total budget that’s going to be non-operated?

Paul T. Horne

We’ve seen that pretty consistently at about 25%. I believe it was 27% in 2012 and based on the activity that we’ve seen to-date, I would expect that number to hang in there in the 25% of our total capital budget.

John Ragozzino - RBC Capital Markets

Great. Thanks very much. I’ll let somebody else hop on.

Paul T. Horne

All right, John.

Cary D. Brown

Thank you, John.

Operator

Our next question comes from Chris Sighinolfi with UBS. Please go ahead with your question.

Christopher Sighinolfi - UBS

Hi, guys.

Paul T. Horne

Good morning, Chris.

Christopher Sighinolfi - UBS

How you doing? Just a couple of quick ones from me; looking at the guidance for ’13 on the various component products, it looks like NGL volume is down about 7.5% year-on-year. Just with that (indiscernible) present in many places and a lot of talk of that today, I am just wondering what if anything you’ve incorporated there for that this year?

Paul T. Horne

Yeah, great question, Chris. We have seen that in the field level and our latest, our guidance takes into account both the full-year 2012, but also what we’ve seen in more specifically in the back half of ’12. So, we’re not expecting that to change materially from what we’ve seen here most recently. We obviously are routing for more infrastructure and the alleviation of that issue. But, yes we did see rejection and that has impaired our results, but on a go-forward basis we’re not expecting that to turn around anytime soon.

Christopher Sighinolfi - UBS

Okay. And then I guess, then on the infrastructure front somewhat related recognizing that you’ve hedged a lot of the Midland-to-Cushing exposure for ’13, just wondering if you can give a little bit more color on what you’re expecting there in terms of pipeline expansions and whatnot that will sort of shape the framework as we think about periods beyond ’13, really as we think about ’14?

James Daniel Westcott

Sure. I think you just staring at the Bloomberg screen we’ve seen how Longhorn has already impacted differentials. I think as of yesterday the posted differential was about $0.25. What we’re seeing in the field was a little bit different than what everybody has seen on the screens, but it's pretty darn close. I think from our understanding that filling that line today and so that might be a little bit artificially depressed, but for the year I think $1.50 is a pretty reasonable expectation for that differential.

Christopher Sighinolfi - UBS

Okay, great. And then I have asked this before, I just want to circle back on it given the fact that some additional peers have talked about moving to monthly distribution structures just wondering what, if you have any updated thoughts on what Legacy might consider on that front?

Cary D. Brown

Chris, its Cary. We haven’t had any of our investors ask for monthly distributions. So, what our stance right now is, it's not a significant move to move from quarterly to monthly. It looks like the market is expecting and wants monthly then that’s not a hard change for us to make. Obviously that’s a Board level decision and we’re following those discussions, there’s several things after that we’re looking at pretty closely that seemed to be something our investors are after, but with [UAN] and Vanguard now going to those, I guess you got to look at the – how that affects the short position as well. So, we’re thinking about it. That’s a long answer to say we’re thinking about it, but we don’t have any plans to look to it today.

Christopher Sighinolfi - UBS

Okay. Great, Cary. Thanks, guys.

Cary D. Brown

Thank you, Chris.

Operator

Our next question comes from Kevin Smith of Raymond James. Please go ahead with your question.

Kevin Smith – Raymond James

Hi, good morning gentlemen.

Cary D. Brown

Hi, Kevin.

Kevin Smith – Raymond James

Congrats on the strong Bone Spring as well. Paul, you might have mentioned this already but, how many more Bone Springs wells do you plan on drilling this year, and maybe if you can lay out the timing of when we should expect those to come on line?

Paul T. Horne

Sure, Kevin. Operate as we plan on drilling two wells in 2013, probably -- currently it looks like we’ll probably pick-up a rig around the 1st of July and drill those two wells. There’s always a possibility that we could drill more than two wells when we get that rig but currently in our plan that’s what we have. We also have a number of non-operated horizontal wells Bone Spring is the majority of those, but those range Kevin from 2% to 25% working interest and there’s probably four or five of those that will be drilled this year. So, on a net well basis that we might get up to 2.5 or 3 Bone Spring wells for 2013.

Kevin Smith – Raymond James

Okay, got you. And then the next question I have is, I guess, are you guys still good with the Concho production forecast? I believe in the press release you were looking for a little over 5,200 barrels a day for Q1 '13 production. But it seems like base backing into the production rate attributed this quarter that you're below that 5,000 mark. Am I looking at it correctly?

James Daniel Westcott

Yeah, Kevin this is Dan. I think we still believe in those production numbers from the Concho acquisition. We mentioned it at the time of the announcement, and then in the equity lease the Q1 production -- what we were trying to articulate was Q1 production for the Concho assets and what we talked about in that context was the significant decline in the Lower Abo assets. And so that’s why we had -- that’s quite the time we didn’t announce a current rate, but instead an estimated Q1 rate. We still feel good about that number. But we still expect those Abo assets to decline pretty steeply and in consistent with what we said before we’re not going to be chasing that here over the next couple of quarters.

Kevin Smith – Raymond James

Okay. So to play that forward, as I think about those assets specifically showing a production increase in Q1, and then potentially peaking out and then the Lower Abo declines setting in for the rest of the year.?

James Daniel Westcott

Well, they’re declining throughout the year. So, on a PDP basis those assets will absolutely -- all of the Concho assets will decline throughout the year. The Lower Abo more specifically will -- is projected to decline approximately 600 barrels a day from start to finish.

Paul T. Horne

And you’ll see some of that Concho PDP work and we talk about come on in the later half of the year and offset those declines which is why you’re not seeing significant growth. You may, just the PDP basis first quarter might be a little higher than the couple of next quarters until some of that capital we’re spending starts kicking in, in the later half of the year.

Kevin Smith – Raymond James

Okay, but I guess back to my original question, any reason to believe that Concho's production is going to accelerate from what you saw from the 10 day period in 4Q or is that the good run rate and assume it just declines off that?

James Daniel Westcott

The 12 day not (indiscernible) …

Kevin Smith – Raymond James

The 12 day, sorry.

James Daniel Westcott

But no, don’t expect a significant change in that.

Kevin Smith – Raymond James

Okay, fair enough. And then, do you happen to have kind of organic growth number for 2012, you feel comfortable about that you want to share with us based off the CapEx? And I get that, with some of the acquisitions and maybe flush production it's kind of tough for us to extrapolate that; but didn't know if you had anything internally you'd want to say that based after looking backwards and spending the CapEx you think you grew production [by X]?

James Daniel Westcott

We’re not prepared to share anything on that, Kevin.

Kevin Smith – Raymond James

Okay, all right. That’s all the questions I had. Thank you.

James Daniel Westcott

I appreciate it.

Operator

Our next question comes from Dan Guffey with Stifel Nicolaus. Please go ahead with your question.

Daniel Guffey – Stifel Nicolaus

Good morning, guys and congrats on a strong 2012. Just touching on Bone Spring again; do you guys still have – I know the last presentation you had out said you have 13 gross locations in the Bone Spring. I guess, is that number still good? And then how many have you booked in your reserves at year end '12?

James Daniel Westcott

Yes, I think that number is still good, I counted up yesterday, and I think we have approximately a dozen gross locations. I have not gone through the reserve report as yet to which ones of those are booked as PUDs; which ones of those are booked as probables at this point; so I’ll check on that.

Daniel Guffey – Stifel Nicolaus

Okay. And then, can you talk a little bit about your non-op cline program, I guess how many wells have you participated in and how many do you expect to participate in, in 2013?

James Daniel Westcott

So, the answer is we’ve participated in three wells so far, with five well over there and we had some results. There’s no question that oil is there in the cline and it's a matter to get drilling cost down to a level that it shows. If you look at other resource trends they should get the drilling cost down. I think we’re -- if you look at the gross level on the first three wells they were in a $9.5 million a piece range not prepared to talk about what the ultimate disperse are, but I’d point you to Devon and Laredo and some of those guys that, that have those reserves out there. I think you need to get the well cost down from $9.5 million and I expect that they will. So, 2013 we’ll continue to participate with those guys, the 5% non-op partner. We’re going to drill the wells that they drill, might be as many as seven wells in 2013. I wouldn’t be surprised if you look, at the way that these private equity companies are build, I wouldn’t be surprised to see some kind of modernization event out of that play in 2013, and at this point we would plan to participate with those guys if they monetize.

Daniel Guffey – Stifel Nicolaus

Okay, great. And then can you kind of talk about your long-term plans of either developing and/or divesting potentially the Lower Abo?

James Daniel Westcott

Currently we’re just doing a deep dive on the Lower Abo, so our current plans are to produce it. I don’t believe we’re going to drill any wells in the first quarter. By the second quarter we may have a little bit of better picture on our plan for that play.

Daniel Guffey – Stifel Nicolaus

Okay, thanks. And then last one for me, can you guys give a broad overview of the acquisition landscape you're seeing and opportunities on the table for acquisitions throughout the Permian, and if you're looking outside the Permian?

James Daniel Westcott

I’ll turn it over to Kyle McGraw, our Chief Development Officer to talk about that.

Kyle A. McGraw

Yes, this is Kyle. We are actively looking at some deals right now. There are, you always have a quite period around the holidays and now it looks like that’s been shared. I’m seeing a lot of marketed packages now, appear to be a number of Permian, Wolfberry type projects that are our there. We looked at those but they’re not our ideal of course. We’re looking at some really high percentage PDP transactions right now, one to Permian, one would be out of the Permian and so we’re seeing – it looks like it's going to be a busy year. I am hearing, I know the North American Prospect Expo is a great place to get a finger on the pulse of that and that seems like there’s a lot of activity going on. The capital demands required by these resource plays are causing some to look to monetize certain assets, and so we do look at those from time-to-time, so we’re very hopeful for 2013 to be similar to 2012.

James Daniel Westcott

We love the see the drilling companies, they always run out of money and when they out of money selling some of that PDP is a good thing, so lots of things to look at.

Daniel Guffey – Stifel Nicolaus

All right. Thanks guys.

Operator

Our next question comes from Michael Peterson with MLV & Company. Please go ahead with your question.

Michael Peterson - MLV & Company

Hi, good morning everyone. I'd like to start, if I could with the per unit cost. Mid-point of your 2013 LOE guidance suggest that you're going to capture about a 10% decrease from 2012 levels. What initiatives or changes could you point to recapture these efficiency gains?

Paul T. Horne

Mike, this is Paul Horne.

Michael Peterson - MLV & Company

Good morning, Paul.

Paul T. Horne

A significant issue with 2012 to 2013 on a per Boe basis is the fact that Concho acquisition those assets are lower lifting costs, a number of those wells are new wells with significantly high rate, so that would drive the overall company lifting cost down. Obviously we’re always focusing on LOE and always focusing on decreasing cost but, what you’re seeing in the guidance is not a projection of successful efforts of that. The majority of what you’re seeing is the fact that the high quality asset base that we bought from Concho is driving the overall Company lifting cost now.

Michael Peterson - MLV & Company

Okay. When I look, Paul, at the results first through fourth quarter of '12, and other than that stub piece would largely exclude the Concho. I notice throughout the year that LOE costs were migrating up. Is there anything within your initiatives that you see to migrate that down, or is it simply going to be on a portfolio basis you'll capture the benefit of lower LOE from the Concho assets?

Paul T. Horne

As I said we’re always looking at opportunities to decrease LOE and working on that issue. The real driver in 2012 on the increase that you saw was, we just had a really tough year of unusual well failures. And what I mean by unusual is a handful of really costly failures, casing collapses, large fishing jobs, sub pumps in the hole with casing collapsed above it. We budget some of that money in every year because you’re always going to have those problems. But starting in late Q2 and through Q3, we had about tow or two and half year’s worth of those kind of projects. I talked about that if you remember Michael, in the Q3 call. We did have some of those projects that we were rigged up on and working on that failed in Q3, carry into Q4, but you did see that with almost 1 million I believe about 800,000 worth of Concho expenses in Q4, you saw our expense from Q3, to Q4 were lying flat which shows that started coming down. Our failure rate overall as a Company is just phenomenal, but in the 0.31, 0.32 failures per well per year rate, so, it's not so much that we got to a significant problem there, in fact I believe if you’d look at 0.3 well failures that’s world class. What we had was a large number of very extensive well failures especially in Q3.

Michael Peterson - MLV & Company

That’s very helpful. Thank you for the detail, Paul. If I could shift gears a little bit, Dan, I'd be interested in your thoughts on the revolving credit facility. And in particular, I'd like to know your thoughts on the right balance between financial flexibility and low funding costs. And if possible, if you could frame your answer relative to your current draw on availability?

James Daniel Westcott

Sure, Michael. So, $300 million of current availability today is a record for us. I think we’re going to continue to try to maximize that balance in keeping low cost of capital. But the key for us is we want to be able to make large acquisitions in a timely fashion, and so I think you’ll continue to see us maintain that large amount of availability. At the end of the day we’re going to be targeting – we’re going to be looking our leverage ratio and we said it several times, but we want to kind of stay in and around that three times leverage. So, our near-term flex will be using our revolver and then we’ll come back and access the capital market, see the debt or equity win when we have something to show forth.

Michael Peterson – MLV & Company

Terrific. Thanks for your help, Dan. That’s all I have this morning.

James Daniel Westcott

(Indiscernible) Thank you, Mike.

Operator

Our next question comes from Abhishek Sinha with Bank of America Merrill Lynch. Please go ahead with your question.

Abhishek Sinha - Bank of America Merrill Lynch

Hi, guys, very good morning. Just had a couple of questions regarding the acquisitions – forthcoming acquisition in 2013. So, what kind of CapEx do you have in mind for 2013 just based on acquisitions; is it something similar that we had in '12 or is it going to be – have you got any color on that?

James Daniel Westcott

So our capital budget for 2013 is going to be $90 million, if we make acquisitions that has some capital that we need to spend with that, then we may increase that number. But we also may make 100% PDP acquisitions which wouldn’t increase that number. So, we don’t really look at our capital tied acquisitions because we don’t know what those acquisitions are going to look like until we make it. So, we just kind of look that on a quarter-by-quarter basis and as we have out there.

Abhishek Sinha - Bank of America Merrill Lynch

Okay. I know you’re probably thinking on – you're looking at some acquisitions in the Permian and some maybe outside the Permian. Is there anything you can provide whether you're looking at mostly oil or is it something that the other shift could shift towards gas based on what deals you might see?

James Daniel Westcott

Yes, right now the two that I was speaking of are very oily – yes, highly oil there is a fact that north coming out that’s going to be very gassy. We’re still open to either we’re a cash flow buyer, so we look for good cash flow, but we do enjoy our oily nature and for every opportunity we have we try to take advantage of that. So we’re open to either right now, we tend to have more oil to look at than I have gas.

Abhishek Sinha - Bank of America Merrill Lynch

Okay, and the last one is like -- I mean in sort of getting an idea of how your acquisition cost basically that’s tax up against the F&D cost.

James Daniel Westcott

You’re asking acquisition cost relative to …

Abhishek Sinha - Bank of America Merrill Lynch

Yes, sir.

James Daniel Westcott

… all in F&D? It has always been cheaper to drill than it has been to buy, but it’s still from an F&D standpoint, and so typically our acquisition cost on a per crude barrel will be higher than our – will be higher than what we can organically add. Specifically I can’t comment on our 2012 because I don’t have those numbers in front of me, but that relationship has held through for us and for the space in general.

Abhishek Sinha - Bank of America Merrill Lynch

Okay. All right, thank you very much. That’s all I have.

Operator

Our next question comes from Praneeth Satish with Wells Fargo. Please go ahead with your question.

James Daniel Westcott

Hi, Praneeth, good morning.

Praneeth Satish - Wells Fargo Securities

Hey, guys, good morning. Just one quick question for me; just wondering with the inclusion of maintenance CapEx in the DCF calculation, does that change your distribution coverage policy at all? Can you just talk about what kind of ratio you expect to maintain over the long run?

James Daniel Westcott

That’s a great question. Praneeth, before we answer that I want to go back to the Bone Spring question somebody has asked before. Paul, I think you’ve got some numbers on that.

Paul T. Horne

Yeah, Dan I have many PUDs we have booked of those 12 gross Bone Spring locations. We have two PUDs booked both of those are in the league unit where we drilled the wells in 2012. We have several other areas of locations that folks are proven up around us. They may not have a horizontal directly offset and therefore meet the requirements from a third party reserve engineers to book at PUD, but active drilling in the area and we’re monitoring those results closely. Of the two wells that we are going to drill this year, one is on league unit and then one is in one of those other areas and that successful well would prove up two additional PUD locations when we drill it.

James Daniel Westcott

Okay. So, Praneeth back to your question on how does going to maintenance capital affect us on a distributions and coverage ratio, and I’ll answer it this way. We look at distributions, we try to look at being consistent so we can sustain over the long-term. We look at our liquidity, we look at coverage. I think you’re going to see us continue to have smoother growth in distributions not these step change growth in distributions that kind of grow into those. So, I haven’t said a number and said okay, now we want 1.2 or 1.1, but I do think you’ll see us take a approach that we want to consistently give distributions at long-term sustainable and some of that has to do with what’s the forward strip look like, what’s the years look like. But you might see us be a little more – have a little more coverage historically than we have because we’re going to the maintenance capital. Is that a fair answer?

Praneeth Satish - Wells Fargo Securities

Yeah, great. Yes. Thank you very much.

Operator

(Operator Instructions) Our next question comes from Eric Busslinger with Marret. Please go ahead with your question.

Eric Busslinger - Marret Asset Management

My questions have been answered. Thank you.

James Daniel Westcott

Thanks, Eric.

Cary D. Brown

Thanks, Eric.

Operator

I’m not showing any other questions in the queue at this time.

James Daniel Westcott

Terrific. Well, we appreciate everybody participating in this morning’s call. As we mentioned earlier we’re really pleased with our fourth quarter and 2012 results. We are looking forward to 2013 and if you guys have any questions, follow-up, please don’t hesitate to reach out. Thanks again.

Operator

Thank you ladies and gentlemen. Thank you for your participation in today’s conference. This does conclude the conference. You may now disconnect. Good day.

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