Legacy Reserves' CEO Discusses Q1 2011 Results - Earnings Call Transcript

May. 5.11 | About: Legacy Reserves (LGCY)

Legacy Reserves LP (NASDAQ:LGCY)

Q1 2011 Earnings Call

May 5, 2011 10:00 AM ET

Executives

Steven Pruett – President, CFO and Secretary

Cary Brown – Chairman and CEO

Analysts

Kevin Smith

Richard Roy

Ethan Bellamy

Justin Kinney

Chad Potter

Operator

Ladies and gentlemen thank you for standing by. Welcome to the Legacy Reserves First Quarter Results Conference Call. Your speakers for today are Cary Brown, Chairman and Chief Executive Officer; and Steve Pruett, President and Chief Financial Officer. At this time, all participants are in a listen-only mode. Following the call, there will be a question-and-answer session. As a reminder, this call is being recorded today, May 5, 2011.

I will now turn the conference over to Mr. Pruett.

Steven Pruett

Good morning thank you for joining us 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 regarding future performance of Legacy and other statements will be forward-looking 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, 2011 as well as our 10-K that was filed in early March as well.

The 10-Q will be released tomorrow morning and subsequent reports will be filed Securities and Exchange Commission. We also encourage you to look at our press releases. Legacy Reserves LP is an independent oil and natural gas limited partnership headquartered in Midland, Texas focused on the acquisition and development of long-lived oil and natural gas properties primarily located in the Permian Basin, Mid-Continent, Rocky Mountain regions of United States.

I’ll now turn the conference over to Cary Brown, Legacy’s Chairman and Chief Executive Officer.

Cary Brown

Thanks, Steve and thanks to our friends for joining us today. Legacy persuaded and produced strong results during the first quarter of 2011 despite weather related production issues, increasing cost environment.

In the fourth quarter of 2010 grew production by 10%, our adjusted EBITDA by 6%, and our distributable cash grow by 10% during the first quarter. In addition, we announced 81 million of acquisitions including a pending 67 million acquisition of Permian properties is scheduled to close today.

We also announced an increase in our 2011 development capital budget to 52 million, which reflects a favorable economic associated with our development projects. We continued to be encouraged by the results for drilling; particularly those associated with our Wolfberry projects, which are exceeding our expectation.

Based on our strong drilling results and recent acquisitions, we increased our quarterly distribution of $0.53 per unit, which will be paid on May 13, 2011. Finally, after deducting all of our 11.9 million of capital expenditures, we generated approximately 23.6 million of cash flow or $0.54 a unit of distributable cash flow, covering our $0.53 distribution, 1.0 three times. I’ll remind everyone that we don’t differentiate between maintenance CapEx and growth CapEx. Clearly, we are seeing some element of growth at this level of CapEx, so we are encouraged by that.

On a cost front, we had a tough cost quarter, but generally after an acquisition, we have some integration cost, we had the weather-related cost, we had some one time stuff. So we’re not really sure whether this is just related to run up in overall oil prices, and how much is sea level rise and how much is one time integration cost. We will be watching that and keep give a little bit handle on that in the quarter to as we see how these costs are going to settle out. We had a pretty good increase in activity in the Permian with the drilling. So we are seeing some cost inflation based on elevated Permian and some of that’s going to be integration and weather-related issues.

So we’ll get a better hang on that in the quarters to come. But overall very pleased with the way the Group managed the weather and the way we’re moving production up with our development projects.

So, with that I’ll turn it over to Steve to go into more details and to the numbers.

Steven Pruett

Thank you, Cary. Cary mentioned $0.50, $0.30 distribution that will be paid per unit to unit holders May 2nd, payable on May 13th that is an increase of $0.01 over the distribution we held flat for 10 quarters at $0.52 two quarters ago. We had $0.005 increase in February and another $0.005 in 1st of May, distribution attributable to the first quarter. And while $0.005 may not seem like a lot of the compounded benefit of distribution increases, they’re steady over time, will build up over time. So very pleased to offer another increased distributions.

Following into the headlines, I will talk a moment about our credit facility and liquidity. As we discussed in the previous press release, we entered into an amended and restated $1 billion five year credit agreement towards an expansion of our term from three years on the prior round to five years currently. We increased our borrowing base from 410 million to 500 million with the anticipated closing – we have closed our $67 million acquisition. We’ll have a press release out on that later.

We expect to have approximately $100 million of pro forma availability under our credit agreement. As you all know, we have the option to request the borrowing baser redetermination by our bank group. We don’t anticipate doing that in the short term, but that’s an option we will consider as we continue to evaluate acquisitions.

We also have options issuing additional units in the public market, what’s your primary retail focused offerings along with the ability to issue public debt down the road if we chose to do so.

So the capital markets have never been stronger in my career with our expanding credit facility, we’re very confident in our ability to finance, not only our drilling program, but also potentially larger acquisitions. We’re pleased to report unaudited preliminary financial information extracted from Form 10-K, which we’ll fall tomorrow morning. I’m going to focus on comparisons of the first quarter of 2011 to fourth quarter 2010 results. This information is contained in our earnings release that was submitted yesterday afternoon, so we encouraged you to review this more detail disclosure, and we encourage to access Form 10-Q available tomorrow morning on EDGAR system on our website.

The headline of course was weather in the first quarter, we had three days of 6 degree weather in February, which is unheard of in the Permian Basin, at least on a sustained basis, and coupled that caused rolling blackout to preserve electricity that was taxed for providing residential heating needs. The state made the decision, forced into decision of cutting off industrial customers and residential customers briefly, what that did is shutdown pumping equipment, which allowed fluids to stop following and then allowed fresh water or more fresh water to setup in some of our facilities and pretty solid and it took several days for that to throw out.

The other unintended result was the power cut off to local refineries, or area refineries and also the curtailment of natural gas that used to fire the boilers. With that abrupt and unplanned shutdown of three refineries in El Paso, border (inaudible) Mexico borders in the Texas, Panhandle. Those refineries were down at least a month and that was over 400,000 barrels per day of refining capacity. With that production in the Permian Basin and Texas Panhandle backed up at the lease locations where our stock (inaudible) we even had to rent frac tanks to store crude temporarily. Fortunately the – once the refineries are back along – we got back to steady-state, but we still have the surplus inventory that’s very slow to work down due to the heightened activity in the Permian Basin as Cary mentioned. And an increase of over 80,000 barrels of oil per day production, thanks primarily to the Wolfberry drilling that we’ve observed since 2006.

All in all our production despite these challenges increased 10% to 11,356 BOEs per day. We believe we had about 550 BOEs per day of impact from the shut in time, due to the freeze ups and the buildup of inventory of about 25,000 barrels. We might note, or will note that we also, we did have to pay for the cost of lifting those barrels in the associated water. So while we have the cost related to that inventory buildup of producing that inventory, we didn’t have the revenue benefit from it.

Our production increase was from 10,337 barrels of oil equivalent per day in the fourth quarter of 2010 and that was attributable to the our acquisition of assets that close just before Christmas, for $100.8 million in the Permian Basin, as well as the terrific results Cary mentioned from drilling our Wolfberry inventory.

Our oil production increased 5%, natural gas production was up 14% and NGL production increased by 7% quarter-over-quarter. Our average realized prices increased, oil was up 9%, $65.53per BOE, excuse me, the BOE settlement price, or realizations were up to $71.21 per BOE that includes the dilutive effect to natural gas and that was up for 9% from $65.53 per BOE in Q4 Oil prices were 11% to 87. 67. Natural gas prices realized were 5.78, roughly flat with 5.71 in Q4; and NGL prices which track oil more so than gas increased 12% to $1.28 per gallon, up from $1.14 per gallon in the fourth quarter.

Certainly our natural gas prices which are – our natural gas is primarily associated with casing head gas that’s rich in the NGL content is favorably impacted by the NGL content in the percentage of proceeds contracts that we have with our gas purchasers and processors.

Production expenses, the other big headline that Cary touched on, increased 19%, a big part of that is the acquisition at year end. So we have more production, more wells to take care of, 19% increase resulted in 21.5 million in Q4. Boe basis which matters more, we were $21.03 per barrel, that was an 11% increase from 18.92 in the fourth quarter. We are seeing industry-wide increases in costs related to higher rig count. Rig counts moved kind of low about 66 in the Permian Basin back in June of 2009 up to over 350 active rigs, what that does is puts demand on well servicing and (inaudible) to complete wells and also to service wells, trucking, stimulation services and a whole set of other services that work for both drilling rigs and for well service operations.

We also incurred significant non-recurring costs. We have three major remedial work over projects to restore production at summed up to $1 million net; another $400,000 related to integration costs on the acquisition at year-end 2010, that’s pretty typical. We acquired a very diverse and disperse set of wells that haven’t been particularly well cared for later in their ownership life.

And as I mentioned the impact of lifting the oil and water associated with that inventory buildup is another $500,000 estimated cost. If sum up those that’s 1.9 million that’s about $1.86 impact backing those out would result in production cost excluding at the loyal taxes of about $19.17 per barrel oil equivalent. (Inaudible) I noticed one of our peers that provide guidance – provided that’s focused on the Permian Basin gave guidance of $20 to $25 per barrel lifting cost. I do think $20 lifting cost environment and a lot of that is dependent on how long we stay at $100 plus oil would you think.

We don’t see a dramatic increase coming after this quarter from where we are, but that is a sea level change from where we were at this time last year and oil prices were $70 range. Our G&A was also up primarily because of non-cash long-term incentive plan, compensation expense of almost $2 million. It is not going to all that we did have cash (inaudible) 2.3 million of those two workout over the long-term. I don’t expect to have – we don’t expect to have that level of cash, incentive, long-term incentive expense in the second quarter for the rest of the year. It was a timing issue.

Overall G&A expenses were 6.4 million or 622 per Boe compared to 5.9 million in Q4. We also experienced our seasonal audit and legal expenses related to our yearend Form 10-K. Our annual report preparation, tax preparation, profit preparation along with the reserve report. You can see the first quarter is very busy period from a standpoint of professional service activity.

We do see return to a more a normal 4 to 450 per Boe G&A cost cash (inaudible) million cost, our SG&A cost in Q2 and beyond, except for first quarter of next year was (inaudible) kind of a seasonal increase.

Turning to hedging activities, we realized $1.7 million of cash settlements in Q1 that was down from 4.8 million in Q4 2010, as we saw oil prices start to increase, oil was 74% hedged in Q – our total production was 74% hedged in Q1 compared to 72% in Q4 that’s pretty typical. We don’t want to hedge all of our production, because as you all have now heard, a lot of our costs are very highly correlated to the price of oil and natural gas, particularly severance (inaudible), which are percentage of revenue.

We also reported an unrealized loss of $77.1 million on a commodity derivatives portfolio and that of course reflects the increase in the oil prices primarily. So our mark-to-market positions on our commodity derivatives increased over the quarter from $14.7 million a year end of 2010 to $91.8 million at 3/31/11. So again that’s responsible for that swing, which wipes out any reported earnings.

Adjustment EBITDA increased 6% to 42.3 million in Q1 that’s up from $39.7 million Q4. CapEx as Cary mentioned was $12 million or $11.9 million in Q1 down slightly from $13.6 million in Q4. We do see a $12 million to $14 million total outlook for the rest of year and anticipate that we will expand $52 million capital budget that we have, if not potential to increase later of the year, because of the great results we are having from our Wolfberry drilling program and our non-operating drilling program primarily in the Permian Basin. We have also recently got some terrific results in some work over activity in Wyoming that we’ll be talking about next quarter in more detail.

Distributable cash flow increased by 10% to 23.6 million, up from 21.5 million in Q4. Our adjusted EBITDA loan development CapEx helped out, but that was offset by lower cash settlements on our commodity derivatives and of course higher cash settlement for a long-term incentive in awards which are necessarily reported by our peers group.

Distributable cash flow per unit $0.50 per unit, 1.02 times covered our $0.52 fourth quarter and that’s up from $0.52 in the fourth quarter, again that covered that $0.53 distribution by 1.02 times. We do expect our coverage to increase as the quarter’s march on with stronger distributable cash flow forecasted for Q2 through the end of the year.

We experienced a reported net loss of $60.4 million or $0.39 per unit, again that’s primarily driven by $77.1 million of unrealized losses on the commodity derivative portfolio and $1 million impairment charge on our oil and natural gas properties. Reversing out that non-cash loss on our commodity derivatives is also normalized earnings of about 16.7 million or $38.03 per unit.

We thank you again for your continued support, I understand that Legacy and our peer group is on sale today for encourage you to encourage our clients to take a second look at Legacy and our peer group yes it was traded off somewhat, but it’s – we are still very very profitable even at $700 oil prices. This model works very very well.

At this time we would like to open up the lines for questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) Our first question comes from Kevin Smith. You may proceed.

Kevin Smith

Hi, good morning gentlemen.

Steven Pruett

Good morning, Kevin.

Kevin Smith

Steve, you discussed, you’ve seen some cost creep in service costs and (indiscernible oil price run up. But would you mind talking a little bit more about that, what specifically on the operating side? And then secondly, what are your vertical well costs in the Permian, I’m hearing a pretty wide range?

Steven Pruett

(Inaudible) driven by natural gas and we’ve seen power cost both from drilling and from acquisition. But certainly labor costs are up across the board, not only internally legacy without field staff and professionals, but also everything from truck drivers to frac crews to rig hands, let’s say, we’re basically friction of unemployment in the Permian Basin and so there is a lot of pressure on labor costs.

There is a lot of new equipment coming into the Permian Basin, which is helpful, that will hopefully prevent the price spikes we saw in 2008 related to capital costs, but those – that new (inaudible) needs to be staffed and this time last summer to about $440,000. Overall, well cost are still under $1.7 million to $1.8 million range. In the Wolfberry, we’re drilling it, which is down to about 10, 5 to 11,000 feet. You may see lower prices by one of our peers (inaudible) Sprayberry very, very at the Midland Basin, which is a Shale.

Those are shallower wells, anywhere from 9 to 9,500 feet and they don’t have as much overall gross interval to treat. So, they will cost that spread and reported around 1.4 million. That’s a different well than what we are drilling. Ours typically come in at a higher rate. I’m not going to comment on whose reserves are greater.

In general, we are not seeing the dramatic spike in drilling completion cost that we saw in 2008 and when we saw well cost raised about 2 million to 2.2 million. So, I think it’s important to look at where given Wolfberry well, if you’re comparing Wolfberry well similar, what we call Eastern angel (inaudible) wing are shallower and don’t have as much overall interval, and typically we are not seeing as high initial rates in those wells as we are with the wells in the Western angle wind where the Wolfberry play started by (inaudible).

Kevin Smith

Okay, great. And then lastly for me the Permian, is there anything you guys are seeing that’s getting you, really bullish on horizontal Wolfcamp play, or is it way too early for you to even kind of debate or talk about general horizontal well?

Steven Pruett

Yes, it’s too early. We just – I just heard for the first time yesterday that (inaudible) was drilling, horizontal Wolfcamp South of one of our development plays, we are having just tremendous results. If you’re going to (inaudible) the wells and Central Upton County, so that’s news to us. We are looking forward to hearing about that. We heard a lot more about and we approved an AFE for horizontal second bonesprings and well and (inaudible) Mexico to be lateral out of existing wellbore, so we are much more economic test about one mile lateral, but there are some rigs I know with other operators are having great success in drilling horizontal second, third pumps doing wells in Southeast New Mexico, and of course, we’re hearing there is more of that going on in (inaudible) and counties in Texas, but we’re less exposed to that area.

So we’re anxious to see our results and to benefit from the signs that our peers have, particularly E&P peers have validated surround HBP resold in New Mexico. But we’ll be easing into it, we’re not leading edge risk takers, but we’re fast followers on the data support side. And Kevin, if we’ve got to see where wells stabilize, IPs are great where the current occurs, what the B factor is and what the stabilized rate is few months after, in some cases a year or more. It’s foolhardy to step ahead and spend a couple of million dollars or in these horizontal Bone Spring wells we are talking about $4.5 million and $5.5 million completed well, so that’s a lot of money when you have $52 million capital budget. So we’re going tread very carefully in that.

But we’re very excited about that and we’re also hopeful that our E&P brethren proves out the horizontal (inaudible) as well, but it’s a head scratcher because our experience is we’re completing 2,000 intervals, 10 to 12 stages and we’re never clear when we complete the well which intervals are going to contribute. And if you’re drilling horizontally you’re fundamentally making a bad on interval over 2,000 foot gross interval and so you’re going to leave a lot hydrocarbons behind. So, there’s a tradeoff there and not to mention you’re going to restart over the cost of the well like horizontal piece of the vertical. So, it’s not the horizontal technique, it’s not for all reservoirs or conditions.

Kevin Smith

No doubt. And lastly for a jump, is there anything to talk about Wyoming? I know you mentioned some workovers maybe we will talk about next quarter, but as far as production everything going and up costs, everything going as well as enough costs are really going towards, you would expect?

Steven Pruett

So not it’s been a really pleasant surprise because last year we had integration challenges, it was – we encountered a whole of wells off-line (inaudible) last year primarily in second quarter and then the third quarter, but it’s not seeing the pressure that technical because we don’t have a drilling been going on in Miami because we have Bakken going on (inaudible) Montana. So that operation is going really well to meet our expectations and we had some terrific results from squeezes and from some well work hours and at pay and increased lift and reactivate well so it’s all the clocking and tackling kind of things that we do in the Permian (inaudible) executing very well up there and adding a lot of value. So we’re excited about there is some drilling into a fair, but we have not convinced that yet, but look for that later this year or next year.

Kevin Smith

It sounds good. Thank you gentlemen.

Steven Pruett

Thank you, Kevin good questions.

Operator

Thank you. Our next question comes from Richard Roy. You may proceed.

Richard Roy

Good morning.

Steven Pruett

Hello Richard.

Richard Roy

Steve, I believe you comment at the end of your prepared remarks, you said that Legacy’s profitable well below $100. Could you walk us through how you determine your CapEx program and specifically what price that is embedded into that 52 million programs for this year?

Steven Pruett

Let me first say that we – when we evaluate project economics for drilling wells, we aren’t assuming the strip or the current price environment. In the past, we’re just about a 64 in more than $70 to $80 range and $4 gas on wait. So they have to generate a risk adjusted economic return, rate of return investment efficiency that’s well above our acquisitions do and much lower price environment.

So during the development inventories very robust and generates your 20% plus rates of return in the $80 $4 range. In terms of thinking about cash available to fund our development program given the heavy amount of hedging we have this year even if we see oil dropped back to 80, it’s not going to affect the cash available to put back in the ground. So I don’t see a pullback in practice. We didn’t plan or put together our plan in our budget last November and amended it in March for the acquisitions that we closed and which other way we worked to view a significant acquisition I think one to close at year end at the Permian Basin now the one that closed today that gives us available cash flow and we will examine that revise our models and then given the attractive inventory we have we will take that excess cash flow and put part of that back in the ground.

So that typically work drives our budgeted CapEx increases. We are not unless we see a pullback like we saw in 2009 (inaudible) which was an unprecedented time global financial crisis, I don’t see it’s adjusting our CapEx budget downward to in a scenario or oil pulls back to $80 a barrel just because we are so heavily hedge for the next couple of years.

Richard Roy

All right. And just a follow-up on the hedging given what we have seen on the strip on oil any considerations for increasing the hedge in the next 12 to 24 months?

Steven Pruett

Well we pretty well topped out our 2011 hedging position at the Olympic very well founded 2012 has a little bit of room, but we’ve capped out our maximum curve, our board mandated hedging policies, and beyond that we do utilize a lot of three way collars to give our industrial upside participation and expect this to be more of that and we can’t layer in and we’ll layer in more 12, 13, 14, 15 hedges and of course, we’ll continue to hedge acquisitions for 3 to 5 years, as we acquire or contract to acquire assets.

So, expect to see that this point on acquisition hedging continuing, as we’ve in the past typically when we sign purchase and sale agreement and then we’ll have selective or opportunistic addition of hedges that we did in Q1 and even in April that have been announced for some longer dated positions, and what we call well off hedges that we put in place as time marches on. And most of those have been three-way hedges, which really take advantage – three rig collars, which really take advantage of the favorable skew and positive volatility of lot of speculators in crude that we don’t see as much in natural gas.

Richard Roy

And just one last question, as you mentioned the acquisitions anecdotally from some of you peer referred that this is somewhat some new entrance meaning that private equity firms are assigned to bid on type of the assets that you’re looking for. Have you seen and any color you could provide on the landscape for acquisition?

Steven Pruett

Yeah, the two (inaudible) take up that surprises to me were and one we did upon and the other we didn’t. One was a private group that is self-financed – I say self-finance. They have bank group. We know their bankers well, we know the principles well and they were east Texas play and they step down on the Permian on a chunky 1000 barrel a day operated asset. That maintained from left field, but it is their own money, it’s no private equity or public money, so it’s kind of interesting to see how that plays out given they are ahead of the pack, and we’re on the leading edge of the pack.

The other scenario that surprised us, although it shouldn’t be surprising is, this is now the second public Gulf Coast to Gulf of Mexico player, I can remember that has jumped into the Permian and the Wolfberry bought some assets from a friend of mine 366 million of some offshore company, has offshore in their name and there’s another Gulf coast company that has had had financial difficulty that survived and bought some Permian position in the Wolfberry. Again these guys are trying to get some legs, trying to get oily and trying to reinvent their company as many others have. So we wish them well, but they are stepping into areas that, they are new to them. So, it will be interesting to watch how they paid out in the Permian.

But it is a shift because the players that were relatively aggressive in the last year were displaced by players that we haven’t seen before. So it’s an interesting dynamic, but for us we continue to see smaller negotiated oil transactions and natural gases, because today a natural gas deal that we’ve – that we liked, that fits us very well, that we are still buying on very accretive terms, but we are not of the mind to pay the kinds of premiums that some companies are paying for the rights to drill in other people’s locations. We have a good 400 blocks drilling inventory and to pay the equivalent of $10,000 an acre for a direct (inaudible) of somebody else’s 40 acre in field or complete the Wolfberry templates as there isn’t something we need to do.

Richard Roy

Thank you very much.

Steven Pruett

Thank you Richard.

Operator

Thank you. Our next question comes from Ethan Bellamy. You may proceed.

Ethan Bellamy

Hey guys, can you just reiterate for me exactly what the one-time acquisition costs are so that we can get sort of a run rate on what the costs would have been otherwise?

Steven Pruett

We stated $400,000 related to some very specific work over’s and the acquisition that closed at year-end, and those were related to putting wells back online. There are also costs $ 700,000 of state wide Rule 15 compliance costs, those that was a rule that went into effect in September, but it was phase in and it accelerates the timeline that we have to remove, disconnect power, which is in a big cost to either wells.

For wells that have five or more years of being shutting or temporarily abandoned, we have to remove surplus facilities and other equipment in for well that have been shudder or temporarily abandoned more than 10 years, we have to plug them and of course those P&A costs don’t necessarily fall through the income statement. There a lot of weighted cost of clean out and given the almost 80 acquisitions that we have done, I think you can imagine, we even heard something we have deal with for mom and pops and we have done that, that was certainly an elevated cost along with.

The cost of operating and shutting wells and bringing them back online and bringing frac tanks to store, all other hustling we have to do in and particularly in February is very costly to and I don’t have a number on that other the number I gave you to 0.5 million to lift 25,000 barrels of oil that sat at an inventory and that. So those are elements of the first quarter that are pretty unusual that we don’t expect to see again.

And we have something was pretty sounding $600,000 project to restore 50 barrels a day in a well that had a sub-pump that basically got with part achieving with sub-pump which is at the bottom with hole, way to go in and finish it and you can say what dude that’s a lot money, but – spending 600,000 for 50 barrel a day well that is solid and declining it variable rate, is money what we’ve spend. It’s just not something we encounter very often along with a couple 100 to $200,000 major casing repairs.

So, yes – we operate 2,000 plus wells. We are going to have problem wells with those some pretty extraordinary problem wells in Q1.

Ethan Bellamy

And so you just mentioned basically four things, one of which you can’t quantify but the 600,000 sub-pump, 400,000 on the acquisition costs and those compliance costs or roughly 200,000 or so?

Steven Pruett

All that, more than 200,000, I can’t quantify, and even I don’t want to double count, those work orders I mentioned, more than $1 million in the (inaudible) in the press release. So there is 1 million, the 400,000 was in the press release. The 500,000 that kind of related to lifting (inaudible) inventory is an approximation basically looking at the inventory build of 25,000 and applying $20 a barrel lifting cost to that. So that’s where that estimate came from. And the last one of compliance is as estimate. I know we send a lot of money but I’ll have a precise cost on it.

Ethan Bellamy

Okay and on a per unit cost basis, I know you won’t give us guidance, but directionally should we expect those to be coming down with volumes going back up?

Steven Pruett

Well, I think for your planning and for your investor sake, I would count on a $20 environment (inaudible) less than 20, unless we oil pull back 70 in the rig count drop. We made some surprise results and as Cary said Q2 looks to be quite tough when it comes out, but we are not banking on being less than 20, with this $100 plus environment, with this 350 plus rig count.

Ethan Bellamy

Is that consistent across all areas? I mean, are you seeing the same type of cost inflation inside Wyoming or Panhandle as you are in the Permian?

Steven Pruett

No, we are not. It’s really a rig count driven and labor and driven issue now. No thing I failed to mention, when Kevin Smith asked the question, we just had a substantial increase in chemical cost, which is logical given this, the base of chemicals is oil and given where oils went up and what we have all seen at the gasoline pump, it’s not surprisingly chemical costs that are up in that significant element of taking care of 3,000 plus operated oils wells that need to be treated for corrosion, considered okay.

Ethan Bellamy

One last question is, talk about some positive. On the Wolfberry, what type of IPs and EORs do you think fit, what type of type curve should we be looking at on those?

Steven Pruett

Well, and since we haven’t put that press, I’m not going to speak on that. I think the, what I’ll tell you is our reserves that we booked for Wolfberry PUDs and problems, of course we do not report problems, but we have internal books on that. And that’s derived from examining, really thousands of wells that we’ve been closely at the wells that offset our particular locations has increased overtime.

So that’s very encouraging. A big part of that increase frankly is gas, we are seeing the gas oil ratio rise after the initial completion and see gas rates at a relatively flat, fortunately its gas that sells at a 30% to 50% premium to Henery (inaudible) the company in GL content, very rich. (inaudible) got – it has heavier NGL components that are more valuable than, say ethane.

So the increase has come to a large measure in the gas side on our drilling on this power 34 lease that’s been opened all the way 15 locations to drill there, we have drilled about five of them so far, may be six today. We are drilling our sixth, has (inaudible) an increase in the oil curve is well, but it’s a little bit early on that. We have got to see another year of history and when the Wolf looks at it next December for our year-end report, I expect we will see increase there. In the past, we were sort of in the 120 MBOE top range, so a lot of our peers were reporting 140 to 180. And I think we are moving towards our peers, although I would say we’re going to end up in the 180 MBOE per well range, but gas is helping a lot and then these higher IPs that we expect will stabilize at higher rates as well will continue to help us with positive revisions on our Wolfberry wells.

Ethan Bellamy

Are you or the industry getting smarter on completion techniques, does that part of the tractors that all commodity price related?

Steven Pruett

No, I don’t think its commodity price related. I think in our case, its, we are in just very good areas in the heart of deeper, thicker (inaudible) trend. I think between middle basin and central basis platform. So roughly south of the middle of the international airport as opposed to lot of other people that are god blessed them for experimenting and now (inaudible) Country. We’re seeing some great results up in the (inaudible) to just north to mid one or got 50% interest of PDC.

So there are people that are branching up geographically that has not been our MO for the most part, we’re seeing very good areas, but we have expanded the number of stages. We started with the total of six to eight and now 10 to 12 and getting part of that because we are in a bigger area. So I’m not sure that its techniques have been more stages and or certainly going to help. We’ll find the way we initially lift the wells somewhat (inaudible) ESP, which we’ve chosen not to that just because of the cost is switching out from an ESP, but I think it is the mere factor and good area and we’ve added a couple of stages to our couple of stages to completions.

Ethan Bellamy

All right guys. (inaudible) out there?

Steven Pruett

Thank you. (inaudible) we need the rain, rooming our water.

Operator

Thank you. Our next question comes from Justin Kinney. You may proceed.

Justin Kinney

Thank you. Good morning.

Steven Pruett

Good morning, Justin.

Justin Kinney

Real quickly, just wanted to touch based on the comment regarding potentially larger acquisitions and just trying to get a sense if you can give us one regarding what do you see that is being more bolt-on style continuance of what has been the strategy or would you potentially look to new geographies to get a larger size?

Steven Pruett

Let’s me answer quickly the fortune really export, but I would say that the acquisition closed today and what in Eddi County Northwest natural gas is a little bit of a twice for Legacy. It is in the Permian very fine quality production, we didn’t pay for drilling, but with improved gas prices down the road, which we all expect someday will have infill drilling to do in every horizontal Wolfcamp wells.

So that while it fits our geography (inaudible) different in that we typically acquire oil production, so there is an example something which is different. We continue to look at transactions and rounding in particular in the midcontinent and we are going to take steps to diversify exposure to primarily PP oil & gas producing properties.

Justin Kinney

Should we think of shift towards more gas way to production as consistent strategy there?

Steven Pruett

What should (inaudible) we’re consistently value buyers and right now oil has made really, really hot and so when oil is really-really hot, and you look at gas it mean just not as favor to the acquisition, we just did had 49 drilling locations on it that you probably wouldn’t drill at $4 gas, but at $6 gas is probably drilled all of them. We would have to pay for any of those in this environment. So we picked up some locations that when that gas (inaudible) we believe it when and not if, we will have those locations and we will have that infrastructure came back. Good pipeline infrastructure, so we felt like that was a good value at this time for our unit holders and we continue to be diligent and it’s always been tough searching for good value to employ on acquisitions.

But we’ve always done it – we’ve done it every year a little bit here and there, and so we continue – we will continue doing that as our base strategy. And we are looking at certain strategic big acquisition. A 1.5 billion company now, it’s time for us to be thinking of that little more transformational start.

So we look at that it will come from a value lands and when we think there is a good value on a big acquisition, we’ll absolutely go execute on that and great experience in branching out at Wyoming, the people up there have done a great job of integrating those assets, integrating the legacy culture on value and so we’d expect we’re in another Basin that would be appropriate that we felt like we could execute in we make that leap, we still think we’re going to be probably in the middle part of the country, up through mid-count Wyoming – kind of had the goal of going from midland and all the way up through Wyoming Canada and that’s what we think there is a lot of assets in there that fit and play to look at.

So I wouldn’t say we’ve ever not been willing to do a big acquisition, but we’re going to keep our value lands and we’re going to see what comes from a big acquisition on that front. Today, very likely that would be a gas acquisition, because gas is still in our favor. We like well, we like are gas, but ultimately we’re cash flow guys and we need things that are accretive to our unit holder. So I don’t think you will us depart from our rigs, which is value, but you’ll see us always searching for where is the value.

Justin Kinney

We do tend to find value more often in smaller deals these days. We’re still always a value buyer and we seem to be finding that more in the deals that are little smaller and a little less competitively market.

Steven Pruett

As a matter fact Johnson, the $67 million transaction that close today is larger deal for us. It’s the right hand side of the (inaudible) but Carl and his team have been very active on the left-hand side of (inaudible) which is a tack on, we’ve closed 14 million of those tack on that were just so interested in existing properties or property next door, existing operations and we are working on this so interest in the area that we now have as an anchor the Eddie County Gas after that spot other operators and interest owners in the area and we looked from all up those, so it is a an ascent to buy more strategy one that occasionally lands the $101 million transaction as diverse asset however the Permian December 22 February 17 for 2010 we closed 13 oil operators, oil fields in Wyoming that’s on the high end and at least 126 wells in Ede county in Mexico was on the higher end but that in terms additional tack on opportunities and acquisition of additional interest in those properties and we are already working on that. So we are still pushing both ends of the dumbbell on our acquisition strategy.

Justin Kinney

Great color guys. I appreciate it that’s all I had.

Steven Pruett

I like the word dumbbell.

Justin Kinney

Thank you Justin.

Operator

Thank you. Our next question comes from Chad Potter. You may proceed.

Chad Potter

Good morning guys.

Steven Pruett

Hi Chad how are you.

Chad Potter

Doing all right, so yeah just wanted to I guess tie together some of the previous questions, given where oil prices are but also service cost creeps, just kind of wanted to get your sense on how you spend the incremental CapEx dollar and to the extent you increased your CapEx with that steer you more towards work over activity the new drilling just because of the cost et cetera going on?

Steven Pruett

Our first color on our cash flow or capital is PDMP behind pipe work over major work over projects now there’s two categories work or some more there is more than two actually but I’ll drill on repair work over which is lease operating expense such as restoring existing production, two major work overs or recompletions that is changing zones. We are large simulations upside lift equipment and other major projects.

Those when identified by our engineering our operations teams get executed right away because there are so profitable, usually have less than a year payout and rates of return in excess of 100%. So those get first call. So we do have a plan of drilling, as you know we are committed to a rig, one rig program, as couple of frac dates from months and with manufacturing efficiency and we are not going to reverse our commitment to that.

But recently as I mentioned earlier we incrementally funded a lateral (inaudible) out of the existing well bore for second bunch spring and recounting in Mexico, it’s a $1.5 million net for legacy belts. So that’s an example of something that wasn’t on our budget at the beginning of the year, but due to the industry activity and the data we’ve now been able to obtain through partners is very attractive and something that has a lot of optionality. It’s got more risks than an operation but it’s worth the way our offshore operators have performed.

We have locations to plot at to, many of which will be grass roots wells that we’ll have to drill. So that’s kind of the way we think about allocating capital as first to the high return projects in existing well bores, second to the committed drilling programs that require planning and longer term commitment to service providers and then third to projects that are emerging higher costs maybe a bit higher risk for legacy that are emerging to cut the industry activity in drilling trends.

Chad Potter

Okay.

Steven Pruett

(inaudible) I would say probably no time in my career has the rate of return on projects has been higher. We talk about costs going up, but costs are going up a little bit and oil prices up a lot, everything we look at is very, very economic and very profitable and what we’re asking is how much money do you put back to ground, and so you will see us – you will see we’re keeping covered is pretty tight. You seem some our peers decide that they are not going to stay positive coverage.

They are going to go negative coverage. We have because everything we’re looking at right now so profitable so good on a rate of return basis and when you get that flush production at a $100 oil it just makes a lot of difference in your rate of return. So that the cost side has not influenced merely as high as the capital nearly as high as the commodity price going up is influencing.

Chad Potter

It’s interesting to see two of our peers sort of abounded coverage model and to buy substantial amount of growth capital and have coverage and all in covered including growth capital and 0.6 – 0.8 ranging that is (inaudible) directions, but it has caused us to open up minds a little bit and as you move a little away from the 1.2 to 1.3 coverage range of the we’re be able to more opportunistic and take advantage of the strong economic as Gary mentioned on the development of inventory.

Steven Pruett

I guess, maybe the follow on to that would be how you have been chose to as far as incremental CapEx versus incremental distribution paid. How do you weigh that I mean the extent that, it would like lay you would have rising coverage going forward. Do you stick with sort of the 0.5% per quarter raise and you will indicate more aggressive there, or do you choose to put that money in the ground?

Chad Potter

Those are the questions we’re asking every day and try to balance out what’s best for the shareholder over the long-term. Right now I don’t think you’re going to see with the I don’t think it’s best for you holders today to make substantial increases in distributions. I think that money is better spent going back in the ground for the long-term. So I think you will see smaller consistent increases in distributions but we’re continuing that question and that’s those are good questions and we try to respond every day to what’s best for you shareholder.

Steven Pruett

That’s a very timely question, that’s one of the essential topic in our board meeting next week, so that’s the balancing act.

Chad Potter

And then I guess just one last little modeling question, (inaudible) taxes on a tax free basis stepped up quarter-to-quarter, how much of that is really just the additional assets or was there anything else going on there?

Steven Pruett

Those asset growth, we’re not seeing any changes in the severance (inaudible) tax rates or staying -in line with what we expected of course those are accruals now and those rendering or bills come out I belief Bill on the summer and June and then we pay them in the Fall all the way to January. So (inaudible) I will say there is some legislation of your city Boston that produce some of the uncertainty around property evaluation techniques for oil and gas properties so that’s a positive. It removed a lot of opportunities around selecting the initial price in the escalator. So we’re pleased with that is a tax saving (inaudible) so I shouldn’t count our chickens before they have hatched but it looks like it got favorable support, but in general county state taxes are coming in on track with historical moments, and they are going up with higher prices obviously.

Chad Potter

So we’re going to get the government actually doing something that make something easier

Steven Pruett

Yeah that will be easier and will result in more money for our county long-term and more stability and that’s a good thing since the schools are all under the (inaudible) due to the budget short fall and taxes we (inaudible) small parts to provide some stability.

Chad Potter

Thanks a lot guys.

Steven Pruett

Thank you Jeff.

Operator

Thank you. Our next question comes from (inaudible) you may proceed.

Unidentified Analyst

(inaudible) from Oppenheimer, how are you guys.

Steven Pruett

Good to hear from you.

Unidentified Analyst

Just to clarify on – do you think that the peers that you are talking about that are kind of getting away from the way that EMP, NOPs used to be, do you think that that going to force kind of a shift of all the companies more toward that business model, I just want to clarify what your thinking was there?

Steven Pruett

I think its opportunity driven, if you have – I was talking to the CFO, one of our peers, very well managed upstream MLP, so gee, we have got a gas inventory -looks like you’re reinvesting less than maintenance CapEx levels which will – nearly all of the 2009 during financial crisis but (inaudible) if you had a bunch of gas locations, would you be drilling and what’s the good point. So it is opportunity driven, if you have them, particularly in some cases you have companies with leasehold that’s expiring and certainly not the case for Legacy or PSE for example, where we are primarily drilling infill wells.

That would be a driver but I think it’s the economics are so attractive and you’re able to develop the scale and expertise to contract a rig and the service providers and execute on it. If you look at what’s being paid for chunky oily assets in the Permian versus what you can build in terms of oil rates reserves through drilling and completions. I can understand their mindset why not, but I don’t think you’re going to see a rush of all aid (inaudible) after next time comes through rush to that model of negative coverage consistently.

Unidentified Analyst

Okay and then...

Steven Pruett

One thing I will point out is negative coverage leads to higher maintenance cap. You cannot spend significantly more of your cash flow and not have significantly hired the clients in future years, so if you are trying to stay long term sustainable that negative coverage is an issue. And so, even though I can say – maybe it make a lot of sense to go drill 400 locations today. You cannot sustain that over – you just turn into a (inaudible) if you look to your PDP or RDP, that needs to be pretty long out that there and at least in my opinion and in our MLP structure with up-stream assets. So it’s something we’re talking about, we’re looking at – we may pushed them up a little bit where we are not going to say at 1.3 coverage and that we’re going to get to 50% coverage.

Unidentified Analyst

That’s right. And I think to Cary’s point, I’d encourage everyone, all the analyst, to examine the PDPRP companies. It’s one thing that have 30 odd RDP or 30% PDP but if you strip away the parts and PUDs and PDNPs and take a look at what the PDPRP is, you get a sense of the PDP decline rate. And that in term dictates what we reserve and production replacement is each year and as Cary noted, as you drill more and more, you have more and more hyperbolic decline like the (inaudible) Wolfberry, the Balkan etcetera and an Eagle Ford and that’s just a steep slope to overcome. Certainly great companies have been built by aggressive drilling like Chesapeake are built very large but that’s not the model for the company that has to pay quarterly distributions.

Steven Pruett

Okay. And then for – on the natural gas side, I guess is the question really relate to the increase in the natural gas forward curve and my understanding was that some acquisitions previous where we’re not getting done because kind of (inaudible) bread was to wide and I guess I was just wondering if we’re seeing -our deal on the natural gas side more likely to get done now that – number one you guys can sign longer term more payable hedges number one and number two pay a little bit more to trying to get that get across the what the what they ask you on the asset.

Cary Brown

And that the asset just that (inaudible) situation I think that seller owners of gas assets and market in general has situated the gases we’re watching gas for the time being until we have an energy call that will leverage it more is going to be that way for a couple of three or four years and four curve is in and that’s helpful for us to get deals done with some of the smaller independents but I think that, I hope that gas will be $6 next one has faded and that’s allowed us to narrow a bit as spread and get it fields done for natural gas.

Unidentified Analyst

Okay. And just to clarify some on the press release, did is it 360,000 MMBTU gas headed the only one you layered down during the quarter or could you try to figure how much – how many additional hedges were laid on the gas side?

Steven Pruett

If you look back at our announcement and I don’t remember the date it’s around April 4 or 5 data on the current base of natural gas acquisition we detailed our hedges and of course you will see detailed description in our SKU, but if you look at the (inaudible) exact area you are looking at although that’s old collar that we put in place so don’t focus on that too much one instrument that fund related to acquisition that as more of a replacement of hedge. We had generally hedged natural gas with slot you can see from the table also providing some swaps and the reason is, we just don’t get positive SKU or there is not enough favorable (inaudible) of quality in the natural gas trading community through motivate us to do collars much less three less three way collars in other words in oil in that portfolio collar or sea more significantly higher than the four is below that swap level.

So you get a positive SKU or a move to the upside so to speak oil and gas there is no such positive buyer. So we typically buy the maximum insurance which is in the (inaudible) of the swap. Excuse me, I said buy we don’t buy we rarely pay and really don’t pay premiums or put premiums or reset or buy up positions we are entering cost source, either costless collar transactions or cost less swaps.

Unidentified Analyst

Okay, thanks.

Steven Pruett

Thank you Salmon.

Operator

Thank you. At this time, I would turn the call back over to Mr. Pruett.

Steven Pruett

Thank you very much some of those extensive and well thought out questions where we’ve had. We appreciate the fine work that the analyst community does and digging through the numbers and Q&A we explained those in a compelling fashion to our investors without whom we could not grow. We can appreciate all of our investor’s loyalty we hope that there are investors that we used to sell off in the sector by yield oriented securities and I wish you all well in the coming quarter.

With that I like to resign and sign off. Thanks for your attention.

Operator

Ladies and gentlemen, we thank you for participating in today’s conference. This concludes the call. You may now disconnect. Have a good day.

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