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Legacy Reserves LP (NASDAQ:LGCY)

Q3 2010 Earnings Conference Call

November 4, 2010 9:30 PM ET

Executives

Steve Pruett – President and CFO

Cary Brown – Chairman and CEO

Paul Horne – VP, Operations of Legacy Reserves GP, LLC

Kyle McGraw – Director, Legacy Reserves GP, LLC

Analysts

Kevin Smith – Raymond James

Michael Blum – Wells Fargo

Chad Potter – RBC Capital Markets

Operator

Ladies and gentlemen thank you for standing by. Welcome to the Legacy Reserves third 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 November 4, 2010. I will now turn the conference over to Mr. Pruett.

Steve Pruett

Good morning everyone. Welcome to Legacy Reserves LP’s third quarter earnings call. Before we begin, we’d 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 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 risk, 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 our earnings release last night, Legacy Reserves Form 10-Q for the quarter ended September 30, 2010, which will be released tomorrow morning November 5, and subsequent reports as filed with the Securities and Exchange Commission.

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 and Rocky Mountain regions.

I will now turn the conference over to Cary Brown, Legacy’s Chairman, Chief Executive Officer and Co-Founder.

Cary Brown

Thanks, Steve and thanks to our friends and unit holders for joining us today. I’m very encouraged by our third quarter results. Despite a slight decline in commodity prices, we realized 11% growth in EBITDA during the quarter due to increased production, lower production expenses and higher cash settlements on our commodity derivatives.

Although we continued to experience gathering and processing issues in the Texas Panhandle, we increased production in the third quarter to 9,804 barrels of oil equivalent per day up from 9,516 in the second quarter. These increases were due to bolt-on acquisitions in the Permian Basin and Wyoming, operational improvements on our Wyoming and other base properties, and increased development drilling. From July 1 through October 4, we closed an additional 8 transactions for approximately $16.3 million, bringing us to a total of 20 transactions for approximately $173 million of acquisitions for 2010.

Our current backlog of potential acquisitions is sizable, and we feel confident about our ability to grow through acquisitions. In addition, we continue to be encouraged by the results of our drilling – development drilling activity and recompletion projects, which are meeting or exceeding our expectations. Finally, we are pleased to report that during the third quarter, even after we deducted $9 million of capital expenditures for development, we still generated $22.2 million or $0.55 per unit of distributable cash flow, covering our $0.52 distribution by 1.06 times. During the year – our year-to-date coverage is 1.09 times and we maintained positive momentum in the third quarter, and look forward to continued growth in the fourth quarter as well as 2011.

I’ll now turn over to Steve to cover our third quarter results in detail.

Steve Pruett

Thank you Cary. As we’ve previously reported, our bank group redetermined our borrowing base maintaining our $410 million borrowing base on our $600 million credit facility in early October. As of November 3, we have approximately $120 million of borrowing capacity under this credit agreement. I’m happy to report that our bank group is very strong, healthy and desirous of advancing additional funds to Legacy, so we don’t see any constrains on growth relative to our borrowing facility.

Furthermore, the equity markets continue to be friendly and the high yield debt market is also very attractive probably even having recently issued, high yield at a very attractive 79% [ph] coupon. Our leverage is modest with a trailing 12-month debt-to-EBITDA of 2.18 times, while our debt-to-EBITDA covenant or credit agreement is 3.75 times. So we have a lot of rooms there.

It’s our intent to maintain a healthy balance sheet and our opportunistic acquisition program. Our debt-to-book capitalization ratio is 45% as of September 30, 2010. With the strong public capital markets in the favorable lending environment, we are very confident in our ability to finance potential acquisitions. Our fuel flow frankly has never been better. I want to thank and acknowledge our employees efforts in this quarter, an excellent quarter in particular given the fact that we were able to restore production on our acquired properties and reduce lifting cost by 10% per Boe. We have very strong momentum coming out of the, into third quarter due to successful development drilling and production improvement projects namely recompletion, major workovers that generated very strong results towards the back end of the quarter.

So we’ll have a full quarter’s benefit from that in the fourth quarter and our drilling momentum particularly in the Wolfberry trend continues into the fourth quarter.

We are pleased to report un-audited preliminary financial information extracted from Form 10-Q, which we’ll file tomorrow. I’ll make comparisons now of the third quarter 2010 to the prior quarter in 2010. This information is contained in our earnings release, and we encourage you to review it in detail along with accessing Form 10-Q which will be available on the EDGAR system and on our website tomorrow morning.

I’ll now touch on the highlights. Production as clearly noted increased 9% to 9,804 Boe per day up from the third quarter’s 9,516 Boe per day due to the increasing production from recent acquisitions, from increased development drillings and from recompletions and workovers. These increases in production were partially offset by a decrease in production due to gathering system in processing plant down time for one of our gas purchasers in the Texas Panhandle. We were down or the Panhandle process was down most of the month of July for a plant turnaround and had additional gathering issues in August. We believe those problems have been reduced somewhat, but it seems to be an ongoing issue for Legacy and other producers in the Texas Panhandle.

Having said that, we were still able to produce our oil wells but we were finding higher back pressure thus reducing productivity. Our Oil, natural gas liquids and gas sales, excluding derivatives settlements were up 2% at $52.8 million, in the third quarter compared to $51.6 million. Average prices, excuse me, were down modestly 2% at $58.51 per Boe compared to $59.62 in the second quarter. And importantly oil was down 2% to $70.21 from $71.78 in the second quarter. Average NGL prices were down 9% and gas prices were up by 3% surprisingly and that’s $5.40 per Mcf compared to $5.26 in the second quarter.

I might add that we received a substantial benefit for our gas sales in the Permian basis in particular, due to the liquids rich content of our casinghead gas. So we received more than a 20% premium to Henry Hub on the sales of wet gas in the Permian basin. I’m also happy to report oil prices were up above $80 a barrel at this time and that’s going to be a nice fourth quarter revenues, depending hangs in there during end this year.

The headlines for this quarter I think is the reduction in production expenses. I think we alerted everyone we had some one time integration and production restoration cost with our Wyoming acquisition in the second quarter. And we’re happy to report we’re approaching more of a steady stage cost in that set of assets. And we’re very pleased with the performance of those assets and acknowledge our Wyoming business units, teams efforts there. Production cost overall were down 7% to $14.9 million, but keep in mind we are operating more production in the third quarter than we did in the second quarter.

So the production expenses per Boe declined 10% to $16.53 per barrel down from $18.44 in the second quarter. In the second quarter $1.5 million of expenses were related to reestablishing production on our Wyoming acquisition that closed in February. G&A costs were $4.5 million, You should note that includes about $1.3 million or $1.45 per produced Boe of non-cash compensation expense related to our long-term incentive plan thus cash at G&A was about $3.58. We did have about $100,000 of cash settlements on our LTIP that adds another $0.15 a barrel of $3.73 all in.

On the commodity hedging front, we realized cash settlements of $6.3 million in the quarter that was up from $4.2 million in the second quarter, 76% of our production was hedged in the third quarter which is pretty typical for Legacy. Due to the increase in the forward curve from the end of the second quarter to the end of the third quarter, we reported an unrealized loss, a mark-to-market loss of $26.2 million on our commodity derivatives portfolio, and that’s compared to an unrealized gain of $34.1 million in the second quarter.

Adjusted EBITDA hit a record level of $35.7 million in the third quarter, that’s up 11% from the prior quarter. On the development front, we as anticipated increased our CapEx related to drilling and major workovers and recompletions to $9 million in Q3 up from $5.1 in Q2. And we do expect even a higher level in the fourth quarter as we’re running a continuous rig in the Wolfberry and we have some co-owner [ph] development activity that’s going on as well in Q4.

Distributable cash flow was down slightly from the second quarter due to this higher level of capital spending, we reported $22.2 million of distributable cash flow that equates to $0.55 per unit, that compared to $0.58 per unit in the second quarter. And the difference is again that higher level of development CapEx for almost $4 million higher in Q3 than Q4. We did pay another $0.52 distributions, I believe this is our 10th quarter of paying $0.52. And as we reported previously, we do expect to resume distribution growth of 2011, related to continued acquisitions efforts.

Our net loss of $20 million is again driven by the $26.2 million of unrealized losses on our commodity derivatives in addition we had a $4.2 million impairment charge on our oil and natural gas properties. And we also had additional negative mark-to-market impact from our LIBOR swaps of $3.4 million over the quarter. So the mark-to-market accounting or the fair value accounting that we do thus creates volatility in our earnings. Fortunately, the fine analysts that cover us are able to reverse those out.

I would draw your attention as always do to the last page of the earnings release. It’s a very useful tool to reconcile net income to adjusted EBITDA and distributable cash flow. Adjusted EBITDA being a measure of the cash generating capacity of our assets, again at record levels. With that line I would point out that the reported interest expense includes the mark-to-market effect of our LIBOR swaps which I mentioned were $3.4 million, cash interest expense were $4.38 million for the quarter, compared to reported interest expense of $8.2 million.

You can also see the impairment related to lower natural gas prices primarily is reversal of the unrealized loss on our oil and natural gas derivatives, makes that reported earnings or loss rather to $35.7 million of EBITDA. And then dropping down to distributable cash flow, reduced EBITDA by the cash settlements on our LTIP program. Those are primarily what we call unit depreciation rights or exercise of options of our employees and we deducted the entire amount of development capital expenditures, which includes both maintenance and growth capital to arrive at $22.2 million of distributable cash flow and that again equates to $0.55 per unit 1.06 times coverage of our $0.52 distribution.

With that I would be pleased to answer any questions as with Cary, and our management team is with us today.

Question-and-Answer-Session

Operator

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

Kevin Smith – Raymond James

Good morning gentlemen.

Cary Brown

Good morning Kevin, I’m glad you were listening. The long pause there had me worried. I thought you stopped making up questions.

Kevin Smith – Raymond James

No worries, always happy to listen in, and I appreciate the color on the call. First question, I know you have one operated rig, I think you mentioned in your prepared remarks. And if I believe correctly, you were talking about adding a second rig. Where do we stand on that and am I right on that one?

Paul Horne

I’ll answer that, this is Paul Horne. We picked up rig in early in Q3 or middle of Q3 and drilled two wells, and let that rig go and then we picked a rig up, in mid-September and plan on running it through the end of the year. So, yes there are two rigs but it wasn’t two rigs coincidentally.

Kevin Smith – Raymond James

So from here going forward, you do plan on maintaining two rigs or is it going to be just one continuous and one kind of off and on?

Paul Horne

One continuous rig.

Kevin Smith – Raymond James

Okay. And then the wells you drilled, was that production and when were those things brought online, and I guess how much of production impact do you think that will have in the fourth quarter to give me more of a first quarter type event.

Paul Horne

No, it’s already started having insight in Q4. We completed the first well and actually brought it online, in September, we had a marginal Q3 impact that wells now has and will have full impact in Q4 as the second well is completed, and flowing backload and the third well is dragged to last week. So now that we have a rig running continuously complete well about every 17 or 18 days since along those lines. So not quite two of them bringing online between now and the end of the year.

Cary Brown

And in addition to that Kevin, we have one outside operated Wolfberry well. Paul, I think it’s about a 50% interest. That’s contributed to Q3’s results.

Paul Horne

It was actually drilled in Q2 and has contributed Q3 results and then we got another non-operated well that we started drilling in Q3 and we’ll keep brought on here in the next 30 days or so. As well as a number of other capital opportunities that are at Wolfberry drilling that have been done of recent.

Cary Brown

We’re not expecting substantial impact in the fourth quarter on the production side, just with the timing probably going to look little bit like this quarter maybe not as good in terms of coverage because of the increased CapEx coming in the fourth quarter.

Steve Pruett

I will way I have – I’m very encouraged by the profile of our third quarter production, the exit rate in the third quarter much higher than the interims rate. So if there is evidence that rig contribution there, better run time in the Panhandle, and if we sustain $80 plus oil prices, I think we could actually exceed one times coverage in the fourth quarter but that’s – those are a lot of factors that have to stay in place to make that happen, but again very encouraged by the results of makeovers and recompletions, and particular (inaudible) recompletion work and ad pay [ph] and upsizing and disposal, upsizing which is what Paul’s group does so well, has had a very significant impact. And we’re very excited about the productivity of that capital.

Kevin Smith – Raymond James

I might have missed it in your prepared remarks, but can you share with us what your exit rate was or do you care to?

Steve Pruett

We never do, I’m sorry to.

Kevin Smith – Raymond James

Okay, no worries.

Steve Pruett

I’ll just say it was an upward ramps from the start of the quarter.

Kevin Smith – Raymond James

Fair enough. And you guys are soothing in really what kind of a hardest market right now as far as Crockett County and Reagan County as far as the Wolfberry activity in the A&D, and different drilling techniques, and I guess new offers coming in. Is there anything out there that you see that may change the way you guys operate or as far as have any sort of interest in horizontal wells or even monetizing some of the formations?

Steve Pruett

We have and Kyle could answer this better than I can here, but we take in a significant recognizance effort on the Wolfbone and Bone Spring plays. It’s clearly the Wolfberry play has had an impact. Legacy is going to continue its drilling program as the big change in our history. We’re very excited about that because we’ll be more efficient and we’ve got a great inventory.

So from that perspective, we must become more exploitation oriented. We’re stepping up our capital expenditures as a percentage of EBITDA substantially as you recall, Kevin we were at about less than 14% reinvestment rate for 18 months during the best (inaudible) of 2009 and now we’re closer to 28% on a run rate basis, and maybe slightly upward from there. We’re very excited about inventory and as you noticed before we have a Board meeting coming up, and we’ll be announcing our 2011 capital budgets in the next couple of weeks and expect significant increase from this year’s CapEx program. It should be around $30 million.

Kyle McGraw

Well I’d answer that question, Kevin I think there is a lot of interest in saying (inaudible). If you look at the Wolfberry play, it go so hot, and it’s going to add substantial barrels. That was block that had a lot of oil in it. It was hard to get out and we are watching some emerging plays to see, if they’re going to be as good as the Wolfberry. We’ve got acreage in just about all of them in some form or fashion because of our footprint. So we’ll watch it real close what’s happening, and in several of those places, we do have some acres that we think are perspective and even take – potentially take into more acreage. Its little early in some of those plays, but I think you’re going to see one of the reason the Permian is so hot, is because there is a lot of oil in mediocre rock out here that new techniques are open enough. So we hope to be a player in those as those plays to middle.

Kevin Smith – Raymond James

All right, thank you. I’ll jump back in the queue. I appreciate your time.

Cary Brown

All right, thanks Kevin.

Operator

(Operator Instructions) Our next question comes from Kevin Smith of Raymond James.

Kevin Smith – Raymond James

Well gentlemen, I wouldn’t expect to jump back that quickly.

Cary Brown

Everyone else was conflicted by some other MLPs call, I suppose.

Kevin Smith – Raymond James

Yes can you comment on the A&D outlook. So maybe I think is pretty hot. Is there a potential to add, or I don’t know, what the private guys are looking at, do you think you’ll see any sort of rush to exit by year-end?

Cary Brown

I’d be surprised if we don’t get some done by year-end because there is a lot of guys that want to get it done by year-end.

Steve Pruett

Kyle McGraw, our EVP of Business can comment as well.

Kyle McGraw

Yes Kevin, we’ve been thinking, it’s really the mid-part of the year that this back half year with tax uncertainty that there is a lot of folks outside that now this said third and fourth quarters of 2010 are time to exit. We are seeing a tsunami of properties to evaluate. We’re probably half way through that right now of projects to work on. And we are continuing to evaluate. So we’re working a whole there on evaluating properties.

If those are the things that exiting now, they’re probably a little late to be able to get it done by year-end, and yet there are those. I’m hearing that still things that might can happen but the challenges in the industry would just due diligence efforts would probably prohibit that from closing by year-end. But yes we’re still in the pick of evaluating and working on numerous projects.

Kevin Smith – Raymond James

And is it fair to say that Q1 will probably be pretty light in that aspect, I mean I would assume that everybody that want to sell stuff would really get it done by and especially they’re doing it by tax reasons, we’ll try and get it done by 12/31 and then probably sit back and reevaluate things until March, April at least?

Cary Brown

That’s a certainly a possibility but I actually think there is going to be some overhang. Some of these deals aren’t going to quiet done and you’ll have some first quarter deals. Once a lot of time you get the machine to divest started, its takes a little while to get it rolled, once it moves to remind their tax reasons are not the only reasons they’re selling it. It’s a time to monetize the market is frothy and good in a lot of ways. So I actually think the first quarter is going to have some overhang from third – from fourth quarter but I really felt it was slow in the first part of this year in the Permian.

So I think there is a lot of pent-up demand and that’s all, a lot of them is rushing for the door and I think that will pullover into the next year too.

Steve Pruett

Kevin and one of the dynamics we’d seen is there are some sellers particularly Wolfberry assets that we’re disappointed in the bids they received and some of them have chosen to hang-on the part of their assets and further develop them. So instead of selling three drilled wells with 100 locations, they’re going to sell 30 wells with 70 locations or maybe another 100 locations next year. So I think we’ll see some Wolfberry hangover if you will into 2011 as well. Along with just continued sale of non-core assets by very focused players that we’ve seen in the public domain and at some point we’re going to see some private equity that company sells, as well. So we’re encouraged about the backlog going into 2011 as well.

Kevin Smith – Raymond James

Got you. And I guess as you look out in 2011, I know your kind of goal is really is to consolidate all throughout the mid-continent and obviously now you’re in Wyoming and got a great footprint in Texas. Is there a chance to really boost kind of Oklahoma and Kansas? Is that an area that you kind of want to get involved in, and if you looked at any transactions there?

Cary Brown

We have looked in that area and we liked that area a lot. So it’s the right opportunity, but we’d like those, a lot of the opportunity comes along, we’d be very interested.

Kevin Smith – Raymond James

Is there a very much deal flow in that, I mean it seems that’s a pretty quiet spot, but I mean do you think there would be enough opportunities to look at stuff to maybe something eventually ahead?

Cary Brown

I do, we’re in really encouraged by – we’ve got an entry into Wyoming and we’ve added a few tack-on acquisitions there and that’s proven to be a good area with some deal flow there. We haven’t got the significant entry into Kansas area or Oklahoma. We just haven’t bought as much in Oklahoma as I thought we might have, but there is some deal flow. It’s not that the Permian seems to be where we get more of the deal flow now, a year ago it wasn’t that way.

Kevin Smith – Raymond James

Fair enough, and congrats again on getting on the operating costs down this quarter, nice job. I’ll jump off. I appreciate the time fellows.

Steve Pruett

All right, thank you Kevin.

Operator

Our next question comes from Michael Blum of Wells Fargo.

Michael Blum – Wells Fargo

Hi good morning everybody.

Cary Brown

Good morning Michael. Thanks for squeezing us in, I know it’s a heavy morning for you.

Michael Blum – Wells Fargo

I’ve been – I was trying to breakthrough, so glad I got in there. Just a couple of questions, maybe just back to something you were talking about before just to clarify, in terms of your strategy in the Permian with some of these new plays developing. When you say that you plan to participate, did you mean the drill bit or did you mean the potentially monetizing some of your assets?

Cary Brown

We’re watching most all of our acreages held by, in fact virtually 99.9% of our acreages held by production. So when we’re participating we’re watching and then we will make the decision whether to drill or bring in a partner on our acreage. To-date we’ve always chosen to drill at our sales. We may not be the first guy to drill it, we may watch and see what happens around us.

But we generally chose to do those ourselves and have had great success with that. If you look at our Wolfberry position, some of that acreage we went out and picked up the acreage, most everywhere we have to drill, came as down spacing on current assets that we have, on assets we bought that has that. And so I think you’ll see us buy an PDP in some of those areas and – but we may actually participate in some acreages as well.

Steve Pruett

No, the timing of your question is very good Michael. We’ve had well proposals from three partners. Two of which are very significant horizontal wells, one in the Granite Wash, one in the Bone Spring. Neither one of those have been spudded, and in the past we’d be inclined to form those valves, but we have to see, I guess in additional development proof of concept around us, coupled with the – are getting comfortable. We’ve got third Bone Spring opportunities in Mexico that one of our public company partners and it’s kind of actually larger interest than they are, have proposed we’re evaluating that.

Our bias is much more to participate today than it would have been in the past due to one of increasing scale to the increasing data that supports the development concept. And three, the economics of drilling oil wells in the Permian basin is still very attractive. So we’re really moving away from trying to monetize those opportunities and more take advantage of them and – take advantage of some partner expertise and expand that on some of our acreages, Cary described we’ve got all acreage all over the Permian basin. So we’ve got exposure. We don’t have big acreage blocks but we’ve still got significant exposure that could impact Legacy’s production and that cash flow. So forming our coverage model and our distribution model.

Michael Blum – Wells Fargo

Okay, got it. So I guess, the next part of that question is obviously some of your MLP peers have actually shifted their business models a little bit and they are more oriented towards drilling because the returns are much higher right now relative to the acquisition market. So how do you think about that with your relative returns in the A&D market, relative to ramping up the drilling?

Cary Brown

We still believe that it’s an acquisition game primarily. We’re not ready to move towards dramatically towards drilling. Drilling is going to be a part of what we do, and it will always be significant. If you look at a long-term model, the more you drill, the steeper your company decline gets, the steeper your company decline gets, the more you have to drill. And so in a distribution vehicle, we believe that acquisitions of PDP properties is primarily the way we’re going to grow. We’re still going to try to hope production flat and maybe grow a little bit, we may grow 3% or 5% with our CapEx program.

We’re not going to try to grow 20% with our CapEx program. We’re going to lean towards a distribution model but by enlarge, we still think that if you’re in that 20% to 30% of EBITDA on your CapEx and you can keep good opportunities in there and distribute the balance of that. It’s a long-term sustainable model, your home production flat, you payout distributions for the foreseeable future, and then have the good or bad exposure to oil prices and gas prices in the long-term. And ours is primarily oil prices and I think 75% of our revenue is oil.

Steve Pruett

NGL.

Cary Brown

And NGL, so that’s the model. We’re going down. We like the exploitation to CapEx and you got to keep doing that. That’s part of who we are, but the big story I think for the future is going to continue to be acquisitions.

Steve Pruett

And we’ll say we’ve made a very tangible policy shift though. We realized, of course Michael you were in the middle of it, we went through an impersonated financial crisis in 2009 and a commodity meltdown that was brief but very steep. And we cut back our capital to a level that wasn’t advisable I mean, it was advisable given the circumstances at that time. But we have realized that maintaining more of a 25% to 30% EBITDA redeployment or redeployment of the EBITDA into the ground, given the economics that we haven’t being more of a manufacturer rather than on again off again job shop is where we want to be. And so that is a commitment that our Board has supported the management team on, moving to a one rig will create a lot of efficiencies and its necessary really to be able to plan your business and manage a more level loaded capital program rather than one that was on in the fourth quarter of 2008 and then off for 18 months.

And not only is it the rig, it’s the flat program of lining up those days. And Paul has been honest for some time to commit to that, and we’re happy that we’ve got to a scale where can do it. Kevin Smith earlier asked about a second rig, we will have a second rig off and on next year to drill shallower into the wells and our water floods or large former fields. That supplement the Wolfberry activity, and clearly some of our peers have seen the merits of more aggressive drilling and we’ve seen it as well within our own inventory, within our own opportunity set that as Cary’s pointed out, that’s steepened our decline but they do offer superior rates of return. And as long as we have continuous program, we won’t see that cliff falling off. We’ll continue to scale-up our production from organic sources.

Michael Blum – Wells Fargo

Great, thank you. That’s helpful. Just two other quick ones. Just on the processing issues. Can you just talk a little bit more about that, it sounds like those will lean into the future and is that sort of a permanent stumbling block or is that some of your things can eventually get cleared up?

Steve Pruett

Let me start and then I’ll turn it to Paul. What happened in July was a plant turnaround that was scheduled to be a week and with old plant and this isn’t old plant. It’s like remodeling an old house. More issues were discovered and that’s usually an annual event, and we – that was a major turnaround we hope and its only hope, that the turnaround next year won’t be nearly as substantial.

The other more lingering problem though is that it’s an old gathering system that’s a vacuum system, and I’ll turn it to Paul to address that part of the equation.

Paul Horne

Yes, I think you hit it right on the head, Steve. What we have seen this year specifically is a lack of maintenance in capital improvement in both the gathering system and the plant. And because of that we’ve seen an increase downtime and I would even say an unprecedented amount of downtime in the Panhandle, specifically from one company that seems to have made a shift in their focus on reinvestment and I assume that has to do with operating margins. So a gas plant with nat gas and NGL is trading where they are. So we hope that will recover and we’ll do a better job, but quite honestly we don’t have a lot of visibility on that.

We talked to those folks frequently and continue to talk to them frequently to try to get an understanding of their capital. It’s a little bit frustrating because, it’s not a place where we can make the decision to spend capital and improve run times, or decrease downtime. We’re kind of at the mercy of gas [ph] plant company.

Steve Pruett

Because of the low productivity those Panhandle wells averaging one barrel of oil per day and 10 Mcf of very rich gas. It’s not economic for either Legacy or another party. We believe to lay a redundant gathering line and displace the incumbent or semi-monopolistic scenario there. So we’re kind of captive and it is very mature field that’s produced for 80 years and probably have some another 80 years to go if manage properly, but it’s a reality of operating that mature field into Texas Panhandle.

And to Paul’s point its residue gas prices improve, it’s likely that the operator will invest more in their gathering system and run the plant more efficiently. I’m encouraged by high oil prices and pretty strong NGL prices right now may encourage them to spend more on gathering maintenance and focus more on run time.

Michael Blum – Wells Fargo

Okay, thank you very much for all the answers.

Steve Pruett

Hope you bet Michael, thanks for continuing to cover.

Operator

(Operator Instructions) Our next question comes from Chad Potter of RBC Capital Markets.

Chad Potter RBC Capital Markets

Good morning guys.

Cary Brown

Good morning Chad.

Chad Potter RBC Capital Markets

Just wanted to I guess sort of connect between the lines on 2011, I know we’ll know more in couple of weeks, but is it pretty safe to say that the Wolfberry rig will stay continuous through 2011?

Steve Pruett

Yes.

Chad Potter RBC Capital Markets

Yes and any plans to go to a second rig in Wolfberry in 2011?

Cary Brown

Not at this point, I think Steve hit it on the head. I think we’ll likely come out of our Board meeting with the further to run Wolfberry rig continuously through 2011 and then I think we’ll continue to do what we’ve done in the past and that is pick up the shallow rigs to drill Reagan County opportunities, pick up the shallow rig to drill Lea County in the Mexico opportunities here and there, but not a continuous two rig program in the Wolfberry and not a continuous second rig on other opportunities besides the Wolfberry.

So I think you’ll see – I think the change that you’ll see in 2011, it will be a typical year, the way we’ve done capital since our inception, with the addition of a Wolfberry rig running continuously during that time period.

Chad Potter RBC Capital Markets

Right, we appreciate the color. And I guess sort of conceptually, I know when you report as far as discretionary cash flow or distributable cash flow you’re using the default CapEx spend, kind of merging that with just maintenance CapEx and how you think about the distribution, I mean where do you feel comfortable, are you comfortable effectively paying out more than you’re spending but – so a coverage less than one when you’re looking at full spend, but perhaps still more than – well more than one when looking at maintenance CapEx?

Cary Brown

I think that’s a fair way to talk about it. We’ve always had the issues we’ve discussed before that in an oil and gas company it’s really hard to define maintenance CapEx. And we think in terms of ranges of EBITDA, that that could be. So I think we’re looking at is on annual basis, we’d like to be at one times covered, but I don’t think we want to be at one times three, and depending on where our balance sheet is, if we were fully drawn on our revolver and that we’d probably move to a 1.2, 1.3 times covered, if we didn’t have much financial flexibility. If we stay at the two times debt-to-EBITDA we think it’s better run closer to 1.1, even 1.0 because when you start looking at the year and you’re going hey, I can 1.1 times coverage and pay down some to debt and or I could drill a few more wells. We’re generally going to have places that we’re going to spend that CapEx.

So I would say we’re going to annually be one times or better. We’re going to have quarters that were less, and quarters that were more. But over in the long-haul if you’re thinking about maintenance cap versus growth cap, you might think of a 1.1, 1.2 times covered. We don’t ever break that out, and we’re not going to I don’t think. So that’s maybe a fuzzy answer too, how we think about distributions.

Steve Pruett

And I think I’ll put it another way Chad, just to be clear, we will not even with growth capital go below one times coverage on an annual basis, that’s not our expectation given our strong hedge portfolio. And as Cary pointed out, even with growth CapEx we are going to be in the 1.1 range for – on an annual basis given 25% to 30% redeployment of EBITDA without – if you backed out growth capital would be north of 1.2, but again we’re not going to, at this point start providing growth capital guidance versus maintenance capital for the time being in anyway.

Chad Potter RBC Capital Markets

Understood. And I guess finally, just going to the LOE run rate, obviously you’ve got it down to mid $16 barrel range after getting the Wyoming issues taken care of. Is that $16.50 more – is that kind of the run rate going forward or can you see yourself getting back more to the lower 15s that you were running pre acquisition?

Cary Brown

Tell me what your past forecast is and I’ll be happy to predict listing color. And I’m not being smart (inaudible) I’m being serious. If oil and gas prices stay in the range they are right now and have been relatively consistent over the last four, five, six months, I believe you’re looking at a pretty realistic LOE run rate that you saw in Q3, perhaps its go up dramatically I think you’ll see lifting price go up. I don’t even want to mention the alternative to that, but the alternative to that would be true as well as if commodity prices dropped, LOE will drop.

But I think we have changed our historical lifting cost with the Wyoming acquisition. The Wyoming acquisition as we told you guys when we acquired it and when we’ve talked about it, since has the higher lifting cost than the Permian. And so I think what you’re seeing today is a pretty realistic run rate with those assets included. They’re north of $20 a barrel. So I think that rates are real roller lifting [ph] costs a little bit. Does that answer your question?

Chad Potter RBC Capital Markets

That does. Thanks a lot guys.

Cary Brown

Thank you, Chad.

Operator

I’m not showing any further questions at this time.

Cary Brown

Very good. We really appreciate the turnout of our analysts and investors that joined us this early morning to hear an update from management on our call. We’re again excited about the results of the third quarter and even more excited about the prospects for the fourth quarter. I think we’re in great shape headed in 2011 and hopefully we’ll get some of these acquisitions tied up and be able to announce some distribution increases going into ‘011. And I’m real proud of the guys here, and what they’ve done and thankful to have good investors that have appreciate that.

So with that I’ll sign off. Thanks guys.

Operator

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the program. You may now disconnect. Thank you and have a great day.

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