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Legacy Reserves LP (NASDAQ:LGCY)

Q1 2012 Earnings Call

May 3, 2012 10:00 a.m. ET

Executives

James Lawrence – Interim CFO, Treasurer, VP

Cary Brown – Chairman, President, CEO

Kyle McGraw – Director, EVP-Business Development & Land

Analysts

Kevin Smith – Raymond James

Ethan Bellamy – Robert Baird

John Ragozzino – RBC Capital Markets

Bernie Colson – Global Hunter

Christopher Sighinolfi – UBS

Operator

Ladies and gentleman, thank you for standing by. Welcome to the Legacy Reserves First Quarter Results conference call. Your speakers for today are Cary Brown, Chairman, President, and Chief Executive Officer, and James R. Lawrence, Interim Chief Financial Officer, Vice President, Finance, Treasurer. At the time all participants are listen-only mode. Following call there will be a question-and-answer session. As remainder, this call is being recorded today, May 3, 2012.

I’ll now turn the conference over to Mr. Lawrence.

James Lawrence

Welcome to Legacy Reserves LP’s first quarter earnings call. Before we begin, we would like to remind you that during the course of this call, Legacy Management will make certain statements concerning the future performance of Legacy and other statements that would be forward-looking statement 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 materially differ from those discussed in these forward-looking statements and you should refer to the additional information contained in Legacy Reserves LP’s form 10-Q for the quarter ended March 31, 2012, which will be released on or about May 4 and subsequent reports as filed with Securities and Exchange Commission.

Legacy’s an independent oil and natural gas limited partnership headquartered in middle of Texas, focused on the acquisition and development of long-lived oil and natural gas properties, primarily located in the Permian Basin, Mid-Continent, and Rocky Mountain regions of the United States. I will now turn the conference over to Cary Brown, Legacy’s Chairman, President and Chief Executive officer.

Cary Brown

Thanks Jim. And thank you our friends and unitholders for joining us here today. Legacy again produced outstanding results during the first quarter, as we increased production, kept our expenses in line despite rising commodity prices, and recently announced our largest acquisition since December 2010.

On April 30, we announced acquisitions of approximately $88 million of producing properties, including our acquisition of Rockies oil properties for $70.8 million that is scheduled to close around May 23. We believe that these acquisitions will increase our distributable cash flow per unit, both over the short and long-term. I really feel good about those acquisitions. They got a profile of the kinds of things that we’ve done really well with, multi-pay, long-lived oil production. It was all PDP, but we think there’ll be some things to do.

One of the things that feels good is that Permian Basin right now is really hot and being able to buy in the Rockies because of the outstanding group we have up there and in some of these other basins really opens up the opportunities. As I’ve told guys around here, it’s nice to have multiple places to shop when you’re looking for acquisitions. And that’s worked out well. And Kyle and his team has done a great job.

We continue to have a good pipeline of deals to look at. We continue to look at lots of deals, and do a few. But we’re really pleased with the ones we’re getting done. We also closed in the first quarter $5.5 million acquisition some Cline Shale acreage. That’s going to be 5% interest in about 100,000 to 120,000 acres operated by FireWheel, which is a company that my brother is a principal in, and we’re looking forward to interesting results there and like our footprint there.

We did reduce our development capital expenditures in the first quarter to $12.2 million to stay within our capital budget $62 billion for the year. And the results from Wolfberry program, they continue to be excellent and exceed our expectations, or we continue to raise our expectations. We’ve been drilling in some really good areas. The fact that we’re reducing CapEx didn’t have anything to do with the performance of what we’re doing there. We’re pretty committed to using all of our development CapEx against our coverage and we’re committed to stay within that 20% to 30% of the EBITDA, that’s why we did that.

We did let the rig go, the Wolfberry rig in March and April; we picked that back up in May. So, would expect with the flush production we’re getting in this quarter that you’d probably see a small decrease in production in the second quarter and then in the third quarter, as the acquisitions kick in and we pick back up with our capital budget, you’ll see those numbers start moving back up.

Based on our quarterly adjusted EBITDA of $55.2 million, we increased our distribution again for the sixth consecutive quarter to $0.555 that we paid on May 11 to unitholders of record (inaudible) April 30, right Jim? On a year-over-year basis, we increase our quarterly distribution by 4.7%. We generated record distributable cash flow in the first quarter of $0.76 per unit, covering our $0.555 distribution by 1.37 times.

So, on all fronts, did well. Really proud of the operations guys, with rising prices – good prices in the first quarter and good production in the first quarter, and we had good LOE in the first quarter. So, the guys have done a good job of staying on top of the expenses and getting production where it needs to be. So, real proud of the team this quarter. I think they’ve done an excellent job and set us up for a really good year.

With that I’ll turn it over to Jim to talk about the numbers in detail.

James Lawrence

We are very pleased with our first quarter results as we increased our production EBITDA and distributable cash flow to record levels, and continue to produce outstanding drilling results. In addition, we recently announced the acquisitions of producing properties were approximately $88 million, and we expect to be immediately and long-term accretive to our distributable cash flow per unit.

On March 30, our now 14-member bank group redetermined our borrowing base at $565 million. As of April 30, we had a debt balance of $342 million. Including the estimate for closing our recently announced Rockies oil acquisition, we had a pro forma debt balance of $408 million, leaving Legacy with pro forma availability of approximately $157 million without an interim redetermination of our borrowing base that would include recently announced acquisitions.

We are pleased to report unaudited preliminary financial information extracted from our Form 10-Q, which we will file tomorrow. I will make comparisons of first quarter 2012 results to fourth quarter 2011 results. This information is contained in our earnings release. And for a more detailed disclosure, we encourage you to access our Form 10-Q which will be available in EDGAR’s and on our website tomorrow Friday, May 4.

Production increased 5% to 14,440 Boes per day in the first quarter of 2012 from 13,750 Boes per day in the fourth quarter of 2011, primarily due to, one, initial production from newly drilled wells; two, production from acquisitions, including a full quarter of production from our acquisition of Permian Basin assets for $28 million that closed on November 14, 2011; three, alleviation of oil trucking issues caused by inclement weather in December that negatively impacted our fourth quarter production; and four, improvement in plant services that negatively impacted a portion of our New Mexico natural gas production during the fourth quarter.

Average realized prices, excluding commodity derivatives settlements, were $70.51 per Boe in the first quarter of 2012, up 3% from $68.70 per Boe in the fourth quarter of 2011. Average realized oil prices increased 8% to $96.62 per barrel in the first quarter from $89.69 per barrel in the fourth quarter. Average realized natural gas prices decreased 14% to $4.81 per Mcf in the first quarter from $5.59 per Mcf in the fourth quarter, and average realized NGL prices decreased 13% to $1.07 per gallon in the first quarter from $1.23 per gallon in the fourth quarter. Our average realized natural gas prices are favorably impacted by the NGL content in our Permian Basin natural gas.

Oil, NGL and natural gas sales, excluding commodity derivative settlements were $92.6 million in the first quarter of 2012, up 7% from $86.9 million in the fourth quarter of 2011 due to higher production and realized commodity prices per Boe.

Production expenses, excluding taxes, were flat at $23 million in the first quarter of 2012 from $23.1 million in the fourth quarter of 2011. Production expenses per Boe decreased 4% to $17.49 per Boe in the first quarter from $18.23 per Boe in the fourth quarter due to increased production in the first quarter.

Legacy’s general and administrative expenses were $6.5 million or $4.91 per Boe during the first quarter of 2012, compared to $8.5 million or $6.68 per Boe during the fourth quarter of 2011. This decrease was primarily due to $1.9 million in additional expenses during the fourth quarter, including a $1.7 million charge and approximately $200,000 of due diligence expenses related to the termination of a potential acquisition.

Cash settlements paid on our commodity derivatives during the first quarter of 2012 were $2.1 million compared to $4.4 million received during the fourth quarter of 2011, with the decrease attributable to higher oil prices during the first quarter.

We also reported unrealized losses of $21 million on our commodity derivatives portfolio during the first quarter, as the impact of increasing NYMEX oil futures prices from the end of the fourth quarter until the end of the first quarter was only partially offset by a decrease in NYMEX natural gas futures prices over the same timeframe.

As a result of these unrealized losses, our commodity derivatives net liability of $8.4 million at December 31, 2011 was increased to $29.5 million as of March 31, 2012. In comparison, we reported unrealized losses of $65.3 million on our commodity derivatives portfolio during the fourth quarter due to increasing oil prices partially offset by declining natural gas prices.

Adjusted EBITDA increased 3% to $55.2 million during the first quarter of 2012 from $53.8 million during the fourth quarter of 2011, as higher production, higher commodity prices, lower ad valorem taxes and lower general and administrative expenses were partially offset by cash settlements paid on our commodity derivatives.

Development capital expenditures decreased to $12.2 million in the first quarter of 2012 from $19.5 million in the fourth quarter of 2011. To stay within our current $62 million development capital budget, we elected not to drill any Wolfberry wells during March and April. While we will resume our Wolfberry drilling in May, our reduction in drilling activity lowered our capital expenditures during the first quarter and will lower these expenditures during the second quarter of 2012 as well.

Distributable cash flow increased to $36.4 million in the first quarter of 2012 compared to $29.4 million in the fourth quarter of 2011. This increase was due to higher EBITDA, lower development capital expenditures, and slightly lower cash interest expense which were partially offset by a $2 million increase in cash settlements paid on LTIP unit awards.

Distributable cash flow per unit increased to $0.76 per unit in the first quarter of 2012 from $0.64 per unit in the fourth quarter of 2011, as higher distributable cash flow more than offset an increased average number of units during the first quarter due to a full quarter impact from our November 2011 equity offering.

We generated net income of $7.4 million, or $0.15 per unit, in the first quarter of 2012, as higher production, and higher commodity prices, lower ad valorem taxes and lower general and administrative expenses were partially offset by higher cash settlements paid on our commodity derivatives, unrealized losses of $21 million on our commodity derivatives, and a $1.3 million impairment charge on our oil and natural gas properties.

We reported a net loss of $58.5 million, or $1.28 per unit, in the fourth quarter of 2011, which included unrealized losses of $65.3 million on our commodities derivatives and an $18.6 million impairment charge on our oil and natural gas properties.

We thank you for your continued support and confidence in Legacy’s employees. We encourage you to review our earnings release in full and read our risk factors and other more detailed disclosures in our Form 10-Q to be filed tomorrow.

At this time, we’d like to take questions.

Question-and-Answer Session

Operator

Thank you. Ladies and gentlemen (Operator Instructions) Our first question comes from Kevin Smith from Raymond James.

Kevin Smith – Raymond James

Hi. Good morning, gentlemen.

Cary Brown

Kevin, how are you?

Kevin Smith – Raymond James

Doing well. Nice quarter. Would you mind giving me an update on the timing of your joint plans for horizontal Bone Springs and the two Yeso wells?

Cary Brown

Sure, Kevin. We expect to start drilling the first horizontal Bone Springs well in late second quarter or early third quarter. We’re working with several different rig companies concerning the Yeso wells. I would expect that those wells will be drilled in the third quarter as well.

Kevin Smith – Raymond James

Got you. And then outside of Bone Springs, Yeso and the Wolfberry, do you have very much capital allocated to other projects, or is that 90 some odd percent of it?

Cary Brown

It’s actually about 75% of it, with the remaining 25% being scattered over numerous different opportunities, both operated and non-operated.

Kevin Smith – Raymond James

Got you. And then, it looks like you picked up some, or at least, Bakken acreage in the Rockies transaction. Is there any chance of getting any sort of non-op AFEs out of that stuff?

Kyle McGraw

Ken, this is Kyle. Yes, we think there is a chance of that. We’ve heard there’s some rumors. We did not have that baked in, but we do hear there is some activity that works its way in that direction, and some re-permitting or some reallocating at the state level has caused some (inaudible).

Kevin Smith – Raymond James

Got you. And then, I believe, and lastly, and I’ll leave CapEx alone and jump off. I believe on your fourth quarter conference call you said you’re going to leave some wiggle room in potentially to update, move your CapEx up a little higher since it’s down year-over-year. What’s your thought process on that? It sounds like based of the press release that $62 million number is kind of where you really want to stay? Is that the way I should interpret it?

James Lawrence

Kevin, if you look at historically what we’ve done, we’ve started the year with a lower CapEx and we’ve grown it over the years as we see operating results and prices. So there is a lot of factors in that. I would not be surprised if you see that number move up a little bit. I don’t think you’re going to see it go from $60 million to $120 million, but it can move up, it historically has moved up from the beginning of the year to the end of the year. We just had to look at how our operating results or determine how the acquisitions – you know, if you do a bunch of PDP acquisitions that you add some cash flow that lets us free up to do some drilling in the second half of the year. So, all of that is baked in. Right now the budget is $62 million, but historically it has increased.

Kevin Smith – Raymond James

Okay, fair enough. Thank you, gentlemen.

Cary Brown

Thank you, Kevin.

James Lawrence

Thanks.

Operator

Thank you. Our next question comes from Ethan Bellamy from Baird.

Ethan Bellamy – Robert Baird

Hi, good morning, everyone.

Cary Brown

Good morning, Ethan?

Ethan Bellamy – Robert Baird

I just want to finish or continue Kevin’s train of thought here. I didn’t really understand in the release why the delay in the Wolfberry drilling. And if the IRRs are strong, why not keep going? Are you worried about oil prices, or is there some other the factor there? Why not go ahead and just expand the capital budget right away?

James Lawrence

Ethan, as you know, looking at our Q1 results, we’ve not made a lot of acquisitions in the first quarter. We’ve come along strong in the second quarter. And typically, the reason we’ve grown our capital budget throughout the year is because of making acquisitions and increasing our cash flow and, therefore, increasing the 20% to 30% of that cash flow number. And since we were a little bit behind on the year in acquisitions in Q1, we chose to stick to the plan, which originally the plan was to rebuild in March and April.

We were doing that to make room to drill the horizontal Bone Springs and then to drill the Yeso wells. It didn’t room in the $62 million budget to run a full Wolfberry rig fulltime throughout the year and doing that work. So that was the reason for it. It was the plan. We actually spent $1 million more than our first quarter capital plan of approximately $11.2 million, because obviously we’re seeing significant price help and the results of the Wolfberry wells were looking really good.

We actually made that plan in Q4 and worked very closely with our drilling company and got them to farm a rig out for four wells, which represents about two months. And once you make those plans, it’s difficult to change them on a short-term change because they’ve already made commitments to the company that was going to drill those four wells. So, we feel good about where we’re at. We think we’re poised to get back up not only with our Wolfberry program, but other capital projects as well.

Cary Brown

Ethan, there’s another factor that you got to look at when we’re looking at managing CapEx, and that’s a significant amount of our CapEx, probably a quarter of our CapEx is non-op CapEx. And with AFEs coming in, we respond to those and we try to make sure we have plenty of cushion to respond to those non-op AFEs because if you go non-consent, you lose that location forever. If we decide to drill a Wolfberry well in 2013 instead of 2012, we still control all that because it’s all PDP. So we want to make sure we have enough cushion in our CapEx program to respond to the good AFEs we get from our partners and make sure – that we do not have as much control over.

Ethan Bellamy – Robert Baird

I thought the AFEs might be a factor. Are they are churning higher than you would have expected at the end of the year when you’re doing your capital budget?

Cary Brown

No, not at all. The wells that we drilled in January and February and completed in February and March were right on AFE, right on capital budget plan as expected.

Ethan Bellamy – Robert Baird

I kind of meant, instead of instead of AFEs going over budget, I meant more AFEs coming in the door than you would have otherwise expected, in terms of your opportunities?

James Lawrence

Actually, we saw a huge increase in non-opportunities in late Q3 and Q4. That was one of the reasons that Q4 CapEx was $19 million. As it is usual in the industry, typically, folks spend the latter part of Q4 and early part of Q1 gearing up. And so we actually didn’t see a significant amount of non-op AFEs in the first quarter. Expect those to pick up, have seen them start to pick up and, if history repeats itself, it will pick up in Q4.

Ethan Bellamy – Robert Baird

Okay. And then just Cary, just a kind of an odd question, I want to make sure I say this the right way, but having known you guys for a while and having made the pilgrimage to Midland, I think I have a good understanding of the reduced execution risk in the benefit in terms of deal flow and sourcing that you get from family relationships. But other investors, or new investors may not have a good appreciation for that. You mentioned the deal with your brother. Could you talk about maybe sort of family relationships within Legacy and how that benefits the partnership rather than being some sort of a red flag that folks might look at if they didn’t understand how you did the business there in Midland?

Cary Brown

Yeah. I’ll let Kyle take a shot and I’ll mouth off.

Kyle McGraw

Yeah, Ethan, I think it is our unique competitive advantage that we touted from six years ago when we went public that being from a basin, being connected, had a lot of relationships, will allow you to hear about deals that maybe your own and those that are publicly marketed. And so, in several cases, in 2012 – 2011, we had relationships that knew about acreage that needed some capital helped, that knew we had a sophistication level to help in those situations. And we did participate then with an eye for, you know, can we handle the whole capital program or not, but it’s good opportunity to get into.

So, yes, there was one last year that helped us get into the (inaudible) and we like the position and the way we’re able to mitigate risk there and have some exposure. And yes, then Cline Shale plays come along, we’re hearing early words about it. And then, we’re able to get in with relationship and this particular one is actually a family relationship that you can (inaudible). So, I do think you’re right. It does give us a unique pipeline, may not be the biggest and largest deals, but we think it’s good deals.

Cary Brown

And then this in the Permian to get under 140,000 acres, there is just not very many places that you can do that. Sterling County and Mitchell County happen to be one of those that felt like it was just the right spot for us. But when you’re in and around the business like we are, we don’t – we are not in the exploration business. That’s not our gain. There are some deals that fit us that we see. So, being able to say no to most of the deals, let’s say yes on the right ones.

But, the overall just being in the network has, I think, allowed us to see things before they get out of the basin and we’re able to pick our spots. And then, we think that’s a pretty good spot in terms of risk reward for what you could get. And we’re anxious to see – Laredo’s had some good results out there, Range has had some good results, Devon’s drilling out there. So, I think they’ll probably start a well late second quarter and maybe by the end of third quarter have something to talk about or some results in that Cline Shale.

Ethan Bellamy – Robert Baird

Thanks, Cary. Thanks, Kyle. I appreciate it.

James Lawrence

Yeah, I’ll just add as well on the FireWheel front, that’s a company that’s being backed by one of the largest private equity sponsors in the space and it also has some major oil companies that are larger partners in that as well. So it’s being run by a guy who used to run the Permian operations for XTL.

Ethan Bellamy – Robert Baird

Thank you.

Operator

Thank you. Our next question comes from John Ragozzino from RBC Capital Markets.

John Ragozzino – RBC Capital Markets

Good morning, gentlemen.

Cary Brown

Good morning, John.

James Lawrence

Good morning.

John Ragozzino – RBC Capital Markets

Can you talk a little bit more about the Cline Shale? What the industry activity levels have been like out there, kind of what’s the results of them, like just the latest and greatest?

Cary Brown

So, you’ve got over there – Laredo has drilled wells, Range has drilled wells. The Laredo wells, I think, are going to average 450 barrels a day IPs and Range just press released that their wells are trending above the 340 MBOs that they were predicting. But you’re looking at pretty new data. So, I’m pretty hesitant to give much color on that other than what’s been publicly announced by those companies. It’s interesting. And really, if you look at the Permian Basin, there is a lot of these kinds of zones that I think are going to be drilled horizontally.

The Wolfcamp is a place we’ve got some acreage that I think will be drilled horizontally. Ours is pretty scattered. So the Cline – and we talked about the Cline, it’s kind of interesting, but we’re a 5% owner in this. It’s really not going to be a driver for our business. The acquisitions is our driver; the Wolfberry drilling where we’re drilling mostly 75% to 100% wells is what drives our business. So this is an interesting idea and its cool place to be and, I think, could have some long term value for our unitholders. But it’s certainly not one that’s going to have a meaningful impact on CapEx this year or even next (inaudible) heats up, it could have some meaningful impact on CapEx.

John Ragozzino – RBC Capital Markets

Okay, thanks. And then, let’s talk about the Wolfberry. I don’t know if you saw there was a (inaudible) released by Devon the other day that was fairly far to the north that extended the play, it was actually horizontal well, to I think the Wolfcamp. Was that anything that is overlapping your acreage? Does that – have you had your eyes on that thing?

Kyle McGraw

This is Kyle. I’ll comment, and I would say horizontals are being attempted in the Wolfberry and in the Wolfcamp throughout the Permian in places that are raising a lot of eyebrows that say that it could work there, could it work here. And so, absolutely, I think some of our Wolfberry acreage, we may look back and think – find that a horizontal leg would be helpful.

And so, we are – while we’re not watching closely that specific well you’re speaking of, we’re hearing anecdotally of many of our offset operators that are considering Wolfcamp horizontals in certain sections within the paved zone. That’s the challenge right now is which member of the Wolfcamp is best suited to the horizontal lateral. So yes, we are watching that around the basin. And it’s happening in more different places that are surprising to us.

Cary Brown

And as I told people at IPAA, there’s not a play that I’m aware of that we don’t have some acreage in the play just because of our scattered acreage footprint, but they are going to be one, two, three, wells here, a well there and as those plays mature and as we continue to buy assets, I think we’ll have more and more. The Wolfbone and the Cline are the only places where we have non-PDP acreage that would expire if we didn’t drill.

John Ragozzino – RBC Capital Markets

Okay. And just one more for me. Just following up on Kevin’s question, up in the Bakken at some of the acquired acreage, would the 100% PDP, where would you expect the non-op AFEs to come from? And what would they will be targeting?

Cary Brown

When we say a 100% PDP, what we mean by that is that’s the way we valued it, that’s what we paid for on our valuation. That does not mean that there’s not unidentified upside opportunity in the acquisitions. And specifically we have visited with an operator that operates a non-op property that we acquired that has informed us that they very likely will (inaudible) Bakken wells in late 2012.

And this would be on acreage that was held because of a deeper or shallower producing well or vertical. And therefore it’s holding this acreage. So we would still classify it as a 100% PDP and now we’re seeing it, due to spacing changes, there may be doing, we probably be responding to some Bakken AFEs.

John Ragozzino – RBC Capital Markets

Thanks guys, good quarter.

James Lawrence

That’s pretty typical of our acquisition history. Quite often we acquired assets that we’re looking at as strictly PDP on the acquisition basis, and that’s what we’re paying for but very frequently we buy things both on operated and non-operated properties that we didn’t pay for and it just brings us opportunities to spend capital effectively.

John Ragozzino – RBC Capital Markets

Thanks very much.

James Lawrence

Thanks.

Cary Brown

Thanks, John.

Operator

Thank you. (Operator Instructions) Our next question comes from Bernie Colson from Global Hunter.

Cary Brown

Hi, Bernie. How are you?

Bernie Colson – Global Hunter

Hi, Cary. How is everyone doing today?

Cary Brown

Great.

Bernie Colson – Global Hunter

So just real quickly, I assume if there was a sequential growth in natural gas production of about 9%, which I think was related to that third party plant, and correct me if I’m wrong on that. But then, secondly, it looks like NGL production declined sequentially from about 4 million barrels to about 3.5 million barrels. And hopefully if you can comment on what was driving that?

Cary Brown

I’ll answer to gas, and I then I’ll hand it over to Jim to answer the NGLs, Bernie. The gas increase was due to a number of things. As you remember, last year we made an acquisition in the Mexico that was strictly a gas acquisition. And Q4 production was impacted pretty negatively due to gas plant and gas restraint issues that at the plant that we revealed where those were alleviated. And so not only did those go away, but we had some flush production from wells being held back by high line pressures here in Q4, and we increased that gas production in Q1. We also saw some increases that were due to plant related issues and our Panhandle assets as well. So I think that’s the most significant piece of the increase in gas.

James Lawrence

Yeah, on the NGL side, we had some plants that were up in Panhandle that experienced some issues over the course of the quarter in terms of processing capabilities and they had some trains that went down. Overall, our NGL production is still a relatively small part of our total production. That’s why we didn’t talk about it in the press release, but it is a – we experienced some issues with some clients up there. That is really the big driving factor of that. And also in the fourth quarter we had production that was a little higher than we expected from some of those wells.

Bernie Colson – Global Hunter

Okay. So, I guess, (inaudible)?

James Lawrence

Yes. Yes, I would say, on a going forward basis, our NGL production out of the panhandle’s probably somewhere between where it was in Q4 and Q1.

Bernie Colson – Global Hunter

Okay. And then, I know you guys said you weren’t drilling any Wolfberry in March or April. Were there any wells completed there in the first quarter?

Cary Brown

Yes there were.

Bernie Colson – Global Hunter

Can you just comment some on what you’re seeing from initial production rates?

James Lawrence

Sure. The majority of the wells that we completed in the first quarter were 40-acre wells. We really have to look when we start talking about IPs and ultimate cues on whether they’re 80-acre wells or 40-acre wells. But the majority of the wells we completed and brought online in Q4 and Q1 were 40-acre wells. And those wells will range from IPs in the 100 Boe to 150 Boe per day, up to 250 Boe or 300 Boe per day, depending on the area and then depending on the well. It is a statistical play. And we see some very pretty high variances. We had a couple of wells that came in at a very high flush production numbers and declined off that rapidly, which is why Cary mentioned that Q1 production was significantly high and probably a little bit higher than we anticipate Q2 production, because of some real high flush production issues in Q1.

Bernie Colson – Global Hunter

Okay. That’s really helpful, thanks. And then, lastly for me, I know you guys have a number of PDNP opportunities in your asset base. And I was wondering if you could talk about how you think about those versus drilling new wells and how you approach that. I know your capital budget is mostly composed of those new drilled wells. But I was hoping you could comment on those PDNPs, if any?

James Lawrence

Yeah, we love those opportunities. And we did every one that we can find. We did a number of them in Q1; have already done a number of them in Q2. The issue with our PDNP, especially what’s in our reserve report, is generally as soon as we find those opportunities, we go do them. They never hit a PDNP category on the reserve report, because when we find the opportunity, we go do it and then convert it into PDP before it ever gets a chance to hit the reserve report as a PDNP. But we love those projects and we do absolutely every one that we believe is a good project. And if we could spend 50% of our capital budget that way, we would. But typically that’s not the case. Typically, on a year-in year-out basis, the $8 million to $10 million of that type of work. And I would anticipate that that will be the case in 2012.

Bernie Colson – Global Hunter

Okay. Do you think that – I mean, it’s just more from my understanding, but is it that there is a lack of those particular opportunities in the asset base, or it just takes time to find those or...

James Lawrence

Great question. The issue is unlike a Cline Shale program, for instance, you’re not talking about big huge blocks of acreage. So that when we find an opportunity you can go do it 10, 20, 30, 40 times with our scattered footprint, which we love, when we find an opportunity we may have one or two wells that we can do that and then it’s something completely different, three counties away. And so, that type of work generally doesn’t lend itself to big huge programs that you can do a lot of opportunities and spend a lot of dollars on. But where do you find those opportunities, you have phenomenal rates of return. And that’s why, generally, we do it before they ever gets hit the reserve report as a PDNP.

Cary Brown

And I would say that that has been our forte also, we’re looking for scattered assets that are deeper, holding all rights. We find lots of serendipity. We will be announcing an acquisition. It’s a 100% PDP, and yet then when our engineering staff gets to really digging through well files. And it does take some time (inaudible) you’ve got to get through them, because we’re adding new properties each day or each quarter. And so our engineers have to methodically go through the files, but we have consistently found opportunities that were not identified at the acquisition date and then are added soon thereafter. So time is a component.

Kyle McGraw

And Bernie, some of it is – we know the opportunity, but until the current zone gets to a certain level, we’re not going to come uphole and complete a different zone and – maybe early in the life we’re pumping the well, and then we’re going to drop a sump pump in later. So, what our engineering staff does really, really well is looking at every one of our wells, everyday and trying to figure out how do we get the most of oil out of this well today.

And, typically, over a year, we’ll have $8 million to $10 million of workovers that increase that production. And that’s what helps us to outperform the curve that – if you just drew a curve on all these wells, they all decline. Historically with that reinvestment, we’ve been able to find new ways to get things out and hold that production flat, and then grow it a little bit with the CapEx program that really we’ve got in place on the drilling site. So the drilling is easy to identify, it’s easy to spend large blocks of capital on; the workovers is not.

Bernie Colson – Global Hunter

All right, that’s great. Thank you, very much.

James Lawrence

Thanks, Bernie.

Operator

Thank you. (Operator Instructions). Our next question comes from Chris Sighinolfi from UBS.

James Lawrence

Hey, Chris. How are you.

Chris Sighinolfi – UBS

Hey, I’m well. Thanks for your time guys. Most of my questions have been hit. I was just curious Jim, when looking at sort of hedge positions added, the 16 -17 period sort, it was more out of curiosity, but seem to be added under the three-way collar arrangements you guys have. I was just curious, is that just affording you guys a lot of flexibility when looking at backward-dated curve or is there something more going on there?

James Lawrence

It’s exactly what it is. I mean, we typically will go in, when we make an acquisition like the one that we’ve just made or the ones that we’ve just made, the several ones that we’ve just made, but in particular the one that was for $71 million in North Dakota and Montana. We typically go and hedge those out for five years with swaps. But looking at where the curve was, we did the first three years in swaps and then (inaudible) three-way collars because we weren’t real keen on locking in $91 and $88 for the last two years.

Chris Sighinolfi – UBS

Got it. Okay. And then Cary, I just wanted touch quickly on sort of the market dynamics around acquisitions. Obviously, you guys were very very active last year. We’ve seen you be very active year to date. I’m just curious, as we get closer to year-end, do tax considerations or some of the private operators become a bigger component uncertainty around what might happen with the Bush era expirations and things like that? Could you just touch on that quickly?

Cary Brown

We hear about that, we talked about that, and we talked to a lot of guys about that. Not very many transactions have I seen that were tax motivated; most of them are lifestyle motivated. Now, if a guy’s at a stage of life where I’m ready to do something different, the tax considerations are important. And that can make him do something, but generally these kind of comes in cycles. We find more interest on the tax side from doing unit deals.

We saw us do a unit deals last year. We’ve looked at some this year. And a lot of guys like the idea of getting out of the headache of operating, and you’re still having cash flows that’s tied to oil and gas income. And they liked this management team. So I think you’ll see us do some new deals but it’s hard for me to predict. It makes a lot of sense that if you think that the election’s going to go away, that we don’t like, you go ahead and sell this year. But if they wait till November, it’s really hard to get a deal done. And so, if we see the presidential outcome to be something that we don’t like, it looks like taxes are going to change, you might see some gas start in the third quarter doing something. Kyle, you might respond, I hadn’t seen a whole lot of tax motivated stuff, have you?

Kyle McGraw

I would agree with you. There is not as much of that. Several years back, it was a much more discussion, and it all happened in the fourth quarter.

Cary Brown

At the end of 2010, yeah.

Kyle McGraw

At the end of 2010, there was lot of grave concern there, but you’re right. You can see a lot of transactions due to that specifically. Chris, I will say that our deal pipeline right now today is significantly more full than it was 90 days ago. So, I do feel like a lot of deals are coming on the market now. And generally, you see a bigger blow in the back half of the year than do the front half. So, I’d say, it’s picking up, we’re having to just allocate our time to focus on some of the deals that make more sense for us.

Cary Brown

Probably (inaudible) trying to figure out what are we going to do, and needing to monetize some assets to figure out where they’re going to go as opposed to tax-motivated gas.

Chris Sighinolfi – UBS

And we see a lot of that on the gas side. All right, well thanks for your time guys and great job this quarter.

Cary Brown

Thanks, Chris.

James Lawrence

Thank you.

Operator

Thank you. And we are showing no further questions at this time gentlemen.

Cary Brown

I appreciate all you guys and your interest and your support of Legacy, and really proud of the team this quarter for a good quarter and look forward to reporting you guys back next quarter. Thanks.

James Lawrence

Thank you.

Operator

Ladies and gentlemen, thank you for participating in today’s conference. That concludes our program. You may all disconnect and have a wonderful day.

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