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Legacy Reserves LP (NASDAQ:LGCY)

Q4 2011 Earnings Conference Call

February 22, 2012 10:00 ET

Executives

Cary Brown – Chairman and Chief Executive Officer

Steve Pruett – President and Chief Financial Officer

Analysts

Kevin Smith – Raymond James

Ethan Bellamy – Baird

Michael Blum – Wells Fargo

T. J. Schultz – RBC Capital Markets

Chris Sighinolfi – UBS

Operator

Good day, ladies and gentlemen and thank you for standing by. Welcome to the Legacy Reserves' Fourth Quarter and Annual 2011 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, February 22, 2012.

I'll now turn the call over to Mr. Pruett.

Steve Pruett – President and Chief Financial Officer

Thank you, (Caron) and thank you for joining us on this fine morning. Welcome to Legacy Reserves LP's fourth quarter and annual 2011 conference call.

Before we begin, we would like to remind you that during the course of this call, Legacy management will make certain statements concerning the future performance of Legacy and other statements that will be forward-looking statements as defined by securities laws. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions. Actual results may 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-K for the year ended December 31, 2011 which will be released on or about February 23, that’s tomorrow and subsequent reports and press releases 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 of the United States.

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

Cary Brown – Chairman and Chief Executive Officer

Thanks, Steve and thank you to our friends and unit holders joining us today. After an outstanding 2010, Legacy continued its strong growth in 2011 as we set new records for production, adjusted EBITDA, and proved reserves. We increased our annual production by 36% to an average of over 13,000 barrel oil equivalents per day. We increased our adjusted EBITDA by 44% to over $200 million and we grew our proved reserves by 20% to 63.4 million barrels through our robust acquisition program and a record $71.6 million of development capital expenditure.

After closing our $100 million Permian Basin acquisition at the end of 2010, we closed 28 transactions during 2011, including $136 million of producing properties, another $5.5 million of undeveloped acreage in the Permian. While approximately 96% of our 2011 acquisitions were in the Permian, we continue to evaluate and expect to close accretive acquisitions in all of our core areas.

Due to our strong results, we increased our distribution every quarter during 2011 resulting in distribution growth of 4.8% since the fourth quarter of 2010. We are pleased to report that during the fourth quarter even after deducting $19.5 million of development capital expenditures and additional $1.9 million of G&A related to the termination of the potential acquisition in Wyoming, we still generated approximately $29.4 million or $0.64 per unit of distributable cash flow with coverage of 1.16 times or $0.55 distribution.

For the year, after deducting all of our $71.6 million of development capital expenditures, we generated approximately $108 million or $2.46 per unit of distributable cash flow, covering our 216 distribution by 1.14 times. We continue to be encouraged by the results of our Wolfberry drilling program, which are meeting or exceeding our expectations. While our Wolfberry program will remain the focus of our operated drilling activity in 2012, our $62 million capital budget also includes two operated horizontal Bone Spring wells and two operated Yeso wells. With the multi-year oil-weighted drilling inventory that's largely within the Permian and our strong acquisition efforts, we believe we are well-positioned for the future and look forward to another highly productive year in 2012.

I'll now turn it back over to Steve to cover the fourth quarter and annual 2011 results in detail. Thanks Steve.

Steve Pruett – President and Chief Financial Officer

Thank you, Cary. We are very pleased with our fourth quarter and record annual results in 2011. With our successful November 2011 equity offering, where we raised $106.7 million of proceeds net of expenses, combined with our amended $1 billion credit facility, we are well-positioned to execute our acquisition development plans in 2012.

As of February 21, 2012, we had $200 million of borrowing capacity under our revolving credit facility, which has a current $550 million borrowing base. This will be re-determined effective April 1 of this year. With favorable conditions in the public capital markets and ample availability under our credit facility, we look forward to another year of strong organic growth and acquisitions. We thank our employees and our directors and all of our unit holders for another solid performance. We thank our investors and our banks for supporting our growth this year.

We are pleased to report unaudited preliminary financial information extracted from Form 10-K, which we will file tomorrow. I will first make comparisons of annual 2011 results to annual 2010 results and then compare the fourth quarter of 2011 to the third quarter of 2011. This information is contained in our earnings release, which was filed yesterday, and for a more detailed disclosure, we encourage you to access that report along with our form 10-K which will be available in the EDGAR system and on our website tomorrow.

For the year, production increased 36% to 13,071 Boes per day compared to 9,611 Boes per day in 2010 driven by our $136.7 million of acquisitions on producing properties and our $71.6 million development capital budget, which was a record for us. And we benefitted from a full year impact of our $101 million Permian Basin acquisition that closed at year end 2010. Our proved reserves as Cary mentioned grew 20% to 63.4 million barrels equivalent, 85% of which are proved developed producing reserves and 63% are oil and natural gas liquids and that’s an increase from 52.8 million at year end 2010.

Adjusted EBITDA increased 44% to $202 million in 2011 from $140 million in 2010. And importantly, we increased our quarterly distributions by 4.8% to $0.55 per unit attributable to the fourth quarter of 2011 that was just paid on February 14 and that’s up from $0.525 attributable to the fourth quarter 2010, and as Cary mentioned, we maintained distribution coverage of 1.14 times for the year.

I will compare further results. Let’s just talk about prices for a moment. We did realize average price increases of 14% increasing on a Boe basis to $70.61 in 2011 that compares to $61.68 per Boe that excludes commodity derivatives. Average oil prices increased 21% to almost $90 per barrel in 2011 and that’s up from $74.02 in 2010. And natural gas prices, surprisingly enough, increased 5% to $6.05 per Mcf in 2011 from $5.76 per Mcf in 2010, and certainly, there is a benefit of our NGL content and our percentage of proceeds contracts with our gas purchasers that help lift that gas price. And average NGL prices increased 23% to $1.30 per gallon in 2011 from $1.06 in 2010.

Oil, NGL and natural gas sales, excluding commodity derivatives, were up to $337 million in 2011, that’s up 56% from $216 million in 2010 and that’s both an increase in production and benefit of increased commodity prices. Production expenses increased almost 40% to $87.6 million in 2011 from $63 million. Importantly though our production per Boe increased only 2% to $18.37 per Boe in 2011 from $17.97 in 2010 and again that 2% increase per Boe compares to a 14% increase in our commodity prices, which are drivers and lifting costs.

Legacy’s general and administrative expenses were $23.1 million in 2011 and that compares to $19.3 million in 2010. The G&A cost per Boe declined to $4.84 per Boe that compared to $5.49 in 2010. Cash settlements received on our commodity derivatives in 2011 were almost flat. We realized about $600,000 of cash settlements in our favor from our commodity derivative counterparties and that compared to $20.1 million received during 2010. Certainly, the increase in commodity price and in particular, oil prices in 2011 decreased our crude oil commodity settlements.

We were 71% hedged in 2011 that compares to 75% in 2010. We reported unrealized gains on our commodity derivatives portfolio of $6.2 million and that does help boost net income. That compared to an unrealized loss of $21.5 million in 2010. As a result of the unrealized gains of $6.2 million, our commodity derivatives net liability at year-end was reduced from $14.7 million a year in 2010 to $8.4 million as of 2011, clearly our oil hedges are a liability. Our gas hedges continue to be a net asset.

Development capital expenditures increased to $71.6 million in 2011, from $32.9 million in 2010. Our increased CapEx development capital in 2011 reflects our continuous one rig Wolfberry drilling program in 2011, which did not start until second half of 2010 due to lack of rig availability and fracture stimulation services. We have realized improved efficiency in our drilling program in 2011, which allowed us to drill more wells. We drilled 92 gross wells and 32.3 net wells over 2011.

We did also experienced some moderate increase in drilling costs, but not commensurate with the increased oil price. They were also our outside operators, who are very active as well and non-operating capital spending accounted for about 25% of our total development capital budget during 2011. At year end, we will report 187 proved undeveloped drilling locations that’s about 126.5 locations and slightly over 8 million barrels equivalent of proved reserves.

For 2012, we have $62 million development capital budget that’s we will drill 54 gross wells, 28 net wells and would also include 24 gross proved developed non-producing project that includes re-completions, re-stimulations, at-pay type projects, major lift equipment upgrades, 24 gross and 18 net PDMP projects.

Distributable cash flow increased 22% year-over-year to $108.5 million, up from $89 million. Distributable cash flow per unit was $2.46 per unit 2011, compared to $2.21 in 2010. We generated net income of $72.1 million or $63 per unit in 2011 as higher revenues and $6.2 million of unrealized gains on commodity derivatives were partially offset by higher expenses, lower realized commodity derivatives settlements, and a $24.5 million of impairment charges primarily on natural gas properties. I will now shift to comparing the fourth quarter 2011 to the third quarter of 2011.

Production was relatively flat over the period at 13,750 Boes per day. As production increased from recent acquisitions, but were more than offset by third-party plant downtime issues that impacted a portion of New Mexico natural gas production and oil trucking delays caused by inclement weather in the Permian Basin during December, which accounted about 7,500 net barrels of crude oil inventory accumulation during that period. Happy to report that these trucking delays were reversed in January and we work that inventory down. So, we are off to a great start in the New Year. And I would say, our curtailments in New Mexico have been resolved with the natural gas processing plant back online

Average realized prices, excluding commodity derivative settlements were $68.70 per Boe in Q4, up slightly, up from $66.49 in Q3. Oil and natural gas and NGL sales excluding commodity derivatives were $87 million in Q4, up from $84 million in Q3. Production expenses increased 5% quarter-over-quarter to $18.23 per Boe compared to $17.41 in the third quarter.

Legacy's general and administrative expenses were $8.4 million or $6.68 per Boe in Q4 of 2011 compared to $3.8 million in the third quarter of 2011. G&A increased approximately $4.6 million due to $1.6 million increase in non-cash unit compensation expense due to an increase in Legacy’s unit price between the end of the third quarter and the end of Q4. There were $1.9 million of expenses related to the termination of a potential acquisition in Wyoming and $800,000 of year-end professional services fees, due diligence expenses on closed acquisitions.

As a reminder, we do have to consider acquisition costs, due diligence related to title, legal, environmental is considered a general and administrative expense and for an inquisitive company, that’s a meaningful factor. And we did add staff as we continue to experience our growth in our assets and our employees to execute our business plan. Cash settlements received on our commodity derivatives during Q4 were $4.4 million favorable compared to $800,000 received during Q3 with the increase attributable in part to lower natural gas prices during the fourth quarter.

Unlike natural gas hedges that’s settled during the same month in which the corresponding volumes are hedged. Crude oil hedge is settled during the month after it corresponding volumes are hedged. This lag effect on crude oil hedges increased our cash hedging settlements by approximately $2.5 billion during the fourth quarter. So,, we had a benefit to the oil hedge lag effects of $2.5 million in Q4, during Q3 we actually realized a reduction of $2.2 million, during Q3 due to the oil hedge lag effect. We were 71% hedged in Q4, compared to 68% hedged in Q3. We also reported unrealized losses on our commodity derivatives portfolio of $65 million during the fourth quarter as the impact of increasing NYMEX oil futures prices from the end of Q3 to the end of Q4 was only partially offset by decreasing the NYMEX natural gas futures forward prices.

As a result to these unrealized losses, our commodity derivatives net asset was $56.9 million as of September 30, 2011 and that was reduced to commodity net derivatives liability of $8.4 million as of year in 2011, which is driven by the increase in oil prices. Adjusted EBITDA for the quarter increased 3% to $54 million during Q4 that’s up from $52 million in Q3, 2011. Development capital expenditures decreased to $19.5 million in Q4 down from $22.8 million in Q3. Distributable cash flow increased 22% to $29.4 million, compared to $24.1 million in Q3 due to higher adjusted EBITDA and lower development capital expenditures. On a unit basis, distributable cash flow was $0.64 in the fourth quarter, up from $0.55 in the third quarter. We reported a net lose of $58.5 million or $1.28 per unit in Q4 primarily due to the $65 million of unrealized lose on our commodity derivatives and $18.6 million of impairment charges primarily on our natural gas properties.

In the third quarter, we generated $125 million of earnings, primarily driven by $106.8 million of unrealized gains on our commodity derivatives. So, you can see our accounting for our fair value accounting for hedges creates great swings on our earnings. And with that, I want to take you to the last page of our earnings release and spend just a moment, to my favorite table that is our net income to adjusted EBITDA and distributable cash flow reconciliation table last page of the press release. Again that was focused on the fourth quarter and your reported net income loss of $58.5 million adding back GAAP interest expense of $2.9 million, DD&A of 24 million, impairment which I mentioned was $18.6 million. Non-cash unit base compensation expense almost $1.6 million. And then the big numbers are the unrealized losses on our oil and natural gas derivatives of $65 million that’s how we compete $53.8 million or adjusted EBITDA.

And then below that line, you noticed cash interest expenses $4.86 million, the difference, the primary difference between the cash interest expense and the GAAP interest expense was about $2.1 million of mark-to-market gains on our LIBOR swaps, LIBOR swap increased during the quarter making our LIBOR swaps and derivatives more valuable. There were only $61,000 of cash settlements on our long-term incentive plan, unit awards and you can see the development capital expenditures of $19.5 million represent all of our maintenance and growth capital expenditures which results in distributable cash flow $29.4 million.

Thank you for your patience in that rather lengthy review of our annual and quarterly results. We thank you for your interest, your support your confidence in Legacy's employees and our business plan. Again, we encourage you to review our earnings release in full and read our risk factors and other more detailed disclosures in a Form 10-K, which will be available tomorrow.

At this time, we'd like to open up the lines for questions.

Question-and-Answer Session

Operator

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

Kevin Smith – Raymond James

Hi, good morning gentlemen.

Steve Pruett

Good morning, Kevin. Always quick to the trigger.

Kevin Smith – Raymond James

I do what I can. Steve, you mentioned that the New Mexico natural gas, I guess, third-party processing plants back on line. Can you give us kind of a range and figure out how much that would or wouldn’t affect Q1? I guess a date when it came back on line, sorry.

Steve Pruett

Yeah, it was back on line in late December, but I am not prepared to give a daily Mcf effect. It was more a bigger volume effect, frankly, that was a revenue effect since we’re talking about drier gas.

Kevin Smith – Raymond James

Yeah.

Steve Pruett

Than the Boes would imply, Paul do you have any color or thoughts on that?

Paul Horne

No. You're absolutely right. In January, we were up about 1 million a day – 1 million cubic feet a day over December and almost entirely due to the gas plant issue in the Mexico facility. I think you’ll see a nice rebound in Q1 based off of that. Of course, you are also going to see the rebound of selling the crude oil inventory that Steve mentioned in his (indiscernible).

Kevin Smith – Raymond James

Okay, thanks. And then, I guess to roll on when we are talking about the trucking oil production, how much your volumes are negative and trucked out and how much of that is swinging on from quarter-to-quarter and I guess how are you looking at that?

Steve Pruett

Well, you know the impact was about 76 barrels of oil per day over the quarter. Of course, it was concentrated in December so the monthly effect was higher. Jim Lawrence, your colleague just reminded me that our gas effect was about 125 Boes per day obviously the Mcfs were higher spread over Q3. Its primarily, the roads are dry and there is plenty of trucks and they basically worked our inventories back down to the levels in the tanks where they should be. So that’s, just think of it as a reversal over 76 barrels a day of impact in Q4 is a simple way to think about it.

Kevin Smith – Raymond James

Got it, and I guess where are you guys on the learning curve for the horizontal Bone Springs well? I mean, I know you drilled one in the second half of 2011, are you getting pretty comfortable with it that you’re targeting two for 2012?

Paul Horne

Yeah Kevin, this is Paul Horne. We did drill horizontal Bone Springs well in 2011. This wasn’t our first horizontal well to drill. We've drilled several at Legacy and many in our private labs in former companies. So, we feel very confident with the drilling that the key in horizontal Bone Springs play is the completion and that was really where we were working on and learning curve trying to take advantage of industry partners that we do business with and try to take advantage of, our contractors that we do business with and are very pleased with the results of the first horizontal well that we drilled in Lea County, New Mexico. It continues to produce at very good production rates higher than anticipated would suggest that we did an excellent job on the completion of that well.

We’ve continued to study a number of wells that were non-operating working interest owners in horizontal Bone Springs wells in a small working interest as well as look at all of the wells that have been completed in the area. So, we feel really good about that. We're excited about drilling and completing the couple of horizontal Bone Springs wells this year and feels like that could set us with another 15 or 20 locations in the future to drill. And that's just on PDP acres that we are currently own and producing that help our production, so we don’t have a clock ticking on the acreage on that.

Cary Brown

Kevin, I couldn't be more excited about our horizontal Bone Springs opportunities and it’s wells smaller than our Wolfberry play the per well reserves, which were not going to close or considerably higher and they should be since the well costs are higher, but the industry activity coupled with our results and I think our capability set us particularly well in 2013 for capitalizing on that in a big way. And I should have mentioned on the monolog that we've got about 500 approved and probable locations now in our inventory. So, we built up some locations. I’ll loosely call possible locations on the undeveloped acreage that Kyle will discuss later if there are questions on it.

Kevin Smith – Raymond James

You guys disclosed which county you're planning on drilling the horizontal Bone Springs well?

Unidentified Company Speaker

Lea County, just across the state line from Texas.

Kevin Smith – Raymond James

Perfect. Thank you, gentlemen for the answers.

Cary Brown

Yeah, Kevin thanks for your interest.

Operator

Thank you. And our next question comes from the line of Ethan Bellamy of Baird.

Ethan Bellamy – Baird

Hey guys.

Cary Brown

Good morning Ethan.

Ethan Bellamy – Baird

Good morning. I'm clearly going to have to take some lessons from Kevin on hitting star ones faster.

Cary Brown

You're still the quickest on issuing reports, so you’ve got him here.

Ethan Bellamy – Baird

So couple of questions, first the oil hedges are below market, below the cash market. Are there any circumstances, where you would look to reset those?

Steve Pruett

To answer that is probably not. It’s not really the game plan, we are going with. I'm not saying we would never find a situation, where we thought that was an important thing to do, but you're just trading cash to look better if you are sold one, buy another. So, I don’t see a situation, that’s not somewhere to contemplate.

Ethan Bellamy – Baird

Okay. And have you guys had anymore sort of input or advice on potential future costs of hedging under Dodd-Frank?

Cary Brown

No, we haven’t. We are anxiously awaiting the impact of that. What I will tell you is when we talk about bringing new banks in your credit facility, one of the most important criteria that Jim Lawrence has do they hedge and there are some very large regional banks that have very healthy balance sheets and when we acquire after their consideration of adding hedging they respond that the Dodd-Frank rules and laws and uncertainties are just awaiting them from adding hedging capability that’s disappointing.

So we see it affecting the number of banks that can and will provide hedging services. We’ve got a couple of our banks recently, European banks drop or terminate their hedging activities. Two of them in particular are very large banks. Global banks are trying to find other ways to accommodate hedging perhaps even just for their lending clients or the borrowers and not on a broad basis. But it is at this point to see Dodd-Frank reducing the number of counter parties and ultimately we expect we will increase the cost due to margin requirements for our counter parties, which we expect will be passed through to us. But no quantification of those costs yet since CFTC still has to finalize. As you know all of their rules and imparts, but certainly the press we've seen in all the weeks in the preliminary rule making around that is disconcerting.

Ethan Bellamy – Baird

So basically increasing systematic risk the exact opposite intent of the legislation?

Cary Brown

That’s exactly right. It’s an irony in case of the federal government creating unintended results with their actions.

Ethan Bellamy – Baird

Alright, the couple more fun questions what's the type Yeso well look like from your perspective?

Cary Brown

Yeah, Paul do you want.

Paul Horne

We are not prepared really to cover that, and I will say just from the public information we’ve read, it’s their most exciting. Well I don’t say it’s most exciting drilling play. But there it has been the highest rate of return drilling play and from the industry activities surrounding as it looks like the rates of return or even better than our average Wolfberry well. So they are certainly the well cost are little lower, the reserves are a little lower, but it’s those projects come to the top of the inventory because of their high rates of return.

Cary Brown

Kyle do you have.

Kyle McGraw

Yeah, Ethan one of the things we're finding in the Yeso play is often pronounced is that there is even debate right now over vertical and horizontal at one edge, where we had some acreage. We are still trying to analyze I would say producers that are in they had significant use about the different way to completed in. And they are those that would say horizontal, we expect the horizontal have to have a much higher EUR. But the verticals appear there is one operator believes that’s the best way to do it and there is better rate of return with less a lower EUR. So anyway right now we're still analyzing that and it’s varies up and down that trend Lawrence for long distance.

Cary Brown

I will admit to not wanting to quote our reserves in our reserve report because they're always lower than what our peers are reporting in their public information. So, I rather appear to be speak to it the Legacy.

Kyle McGraw

The Bone Springs, the Yeso and the plays that are happening in Permian, Permian's about as hot as you can be right now. And we have acreage in every one of those plays because of our PDP and we have the opportunity to sit and watch and watch a few more verticals and horizontals and then go in and do what we think is best and it allows us to de-risk our capital significantly by watching other's risk theirs. So, we got a really good footprint to go from those Yesos look interesting, horizontal Bone Springs looks interesting. We’ve got some other plays that are starting to heat up that maybe interesting that we've got acreage in. So, it’s a fun time to be in the oily basin.

Ethan Bellamy –Baird

Got it. I clearly need to work on my pronunciation of the play. I am still trying to figure out how to say Wolfbone was a strict face.

Kyle McGraw

Everyone has several things, Eagle Ford, instead of Eagle Ford.

Ethan Bellamy –Baird

One line question, so Chesapeake is looking to sell their Permian, I assume that whole package probably is a little bit more than you guys could buyoff, but what implications that if any should we kind of takeaway from that trade if it occurs and would you be looking for any scraps from that deal if they became available?

Cary Brown

Ethan, I would say, right now we’re trying to look around the edges for scraps and it is very large right now, but we are trying to analyze and decide are there any other pieces? Coincidentally, we are marketing some other pieces out in the Wolfbone play as that announcement was made. So, while we are hopeful, it may get broken up and/or us having identified some properties that are near us we could deal with the successful buyer on that.

Kyle McGraw

Anytime, you could ask just start to move around that opens up the market a little bit. And so we're – I feel pretty good about the inventory that may come on the market and is coming on the market in 2012, didn’t see quite as much in '11 as I thought we might, but the downside or the upside, I guess at low gas prices is guys are needing to find ways to fund the drilling programs differently. We are a good place for them to monetize those.

Ethan Bellamy –Baird

Alright, thanks Kyle. Good quarter.

Steve Pruett

Thanks a lot.

Operator

Thank you. And our next question comes from the line of Michael Blum of Wells Fargo.

Michael Blum – Wells Fargo

Hi, good morning guys.

Cary Brown

Good morning Michael, how is New York?

Michael Blum – Wells Fargo

Still warm, still very warm.

Cary Brown

Not the gas business.

Michael Blum – Wells Fargo

Yeah. Two quick ones from me, one, I am just curious why your CapEx budget for 2012 is lower than '11 and should we expect that, that will tick up as the year goes on as you identify projects?

Steve Pruett

That’s not a reduction, because we don’t have great projects to do. We have plenty of projects. I think we've got about a six-year inventory right now of projects, that’s more of the discipline that we have used of trying to maintain with all of our development capital expenditures in of having coverage. And so if oil prices hold and the capital works as well as we think it might, you might see us increase that throughout the year as we have historically in the past, but we try to set a CapEx that I am happy to say that as long as we have been doing this, we have never had a year, where we didn't generate more cash than we spent, if you include development capital and distributions. And so we've been able to maintain positive coverage every year throughout the commodity cycles. And to me that's thee MLP structure. We kind of walked that tight rope of wanting to be a C-Corp, because we are seeing all the opportunity, but we were really designed for as a cash distribution vehicle and to provide long-term sustainable distributions to our unit holders.

And so to-date, we have maintained that discipline and that's why you saw us go from 71 to 62 if commodity holds and we outperformed as we have historically, then you might see us loosen up in the third and fourth quarters as we have. But that’s kind of the base target that gets us about the right percentage EBITDA maybe even a little bit more, but in these high commodity prices we want to kind of lean into the CapEx program. And we always run the balance you spend it on CapEx, you spend it on distributions to unit holders, and we are trying to thread that needle.

Cary Brown

So, I would reiterate it’s not an indication of limited opportunities. We had in excess of opportunities.

Michael Blum – Wells Fargo

Okay. And when you are setting that budget, are you using in oil price that's below current market or using just strip or how what type of what numbers you are looking at?

Steve Pruett

Would be below the current market.

Michael Blum – Wells Fargo

Okay, got it. And then just on the borrowing base re-determination that comes up next, any thoughts on how that might move just given the gas prices are lower? Does that have any material impact for you?

Cary Brown

Well, we think the oil price increase by our bank group and their forecast would more than offset the decrease in gas price. There is no doubt the gas price decks banks are using $0.50 or $1.50 not far off the current strip or what your banks, what you and your colleagues are projecting. The oil prices obviously are far from the strip, more in the order of $75 a barrel, but that still an improvement of the couple of dollars $4 to $5, well max to $5 a barrel and $2 sort of $3 a barrel in the out year. So given our oil leverage, we think those will wash and then the conversion of PUDs and probables to PDP will be big benefit. Of course that’s partially offset by the runoff since we project forward and then we’ve had some incremental acquisitions although they’re small they do add up and help. So, all in all, I think we’ll better than preserve our current position and we will be reporting that in late March.

Michael Blum – Wells Fargo

Great. Thank you, guys.

Cary Brown

Thank you, Michael.

Operator

Thank you. And our next question comes from the line of T. J. Schultz from RBC Capital Markets.

T. J. Schultz – RBC Capital Markets

Hey guys good morning.

Cary Brown

Hey T.J.

T. J. Schultz – RBC Capital Markets

Just a couple of quick ones, I guess following up on the Yeso wells. Can you just remind me kind of the gross well costs there and you said they’re lower and then what your working interests are on those wells?

Cary Brown

I believe in the reserve report we have those at a little less than $1.5 million about $1.4 million if I remember correctly. We’ve not (season) to date and so we haven’t worked that out completely. We are planning on drilling, Kyle had mentioned that we’re looking at horizontals across the lease lands premises as well as verticals across the lease land from those. We’re currently planning on drilling two vertical Yeso wells and I anticipate that there will be in that $1.4 million, $1.5 million range.

T. J. Schultz – RBC Capital Markets

The working interest is 100%?

Cary Brown

On those it is.

Kyle McGraw

We’ve another 14 or so locations, partnership with Clayton Williams that call those 45% yes, working interest. Not sure if those will be drilled this year or not, but (indiscernible) one never completely knows.

T. J. Schultz – RBC Capital Markets

Okay. I guess then just following up on 2010 CapEx, your non-op CapEx in ‘11 was about $18 million, are you assuming a similar amount from non-op in 2012?

Steve Pruett

Yes. We’re still in that, year in and year out we’ve been in about 25% range that runs pretty close and we’re anticipating about 25% of our $62 million CapEx budget will be non-op. That’s something that we constantly have to manage and that can change very quickly depending on AFEs we receive from partners. We had a couple of very large projects and significant non-operating projects. In fact that’s actually one of the big reasons, why we increased our capital budget in 2011 from the $60 million range that you see now to the $70 million range late in the year because we have received some AFEs from our partners that we thought we are good at AFEs. That we wanted to participate in and that’s actually one of the ways I would have answered the question earlier about decreasing from 70 to 60.

One of the reasons that we are putting at 60 is to give ourselves some room so that if we see that kind of activity from partners again it will give us room and we can still maintain positive coverage, increase in the capital budget on those non-op opportunities. Just kind of depends on balance act it something that we don’t control, but our experience also says that we had some very opportunities come from our partners and we look forward to bring in those opportunities in and comparing to the work that we have to do.

Cary Brown

And T. J. we are maintaining control of the Wolfberry rig we are going effect subcontracted out, not legally, but we will maintain access to the rig and our frac scheduled throughout the year. So, we will still maintain our manufacturing process not to back in to the business in taking rigs and frac crude.

T. J. Schultz – RBC Capital Markets

Great, thanks for the color.

Cary Brown

Thank you T. J.

Operator

Thank you. And our next question comes from the line of Chris Sighinolfi from UBS.

Chris Sighinolfi – UBS

Hey, good morning guys.

Steve Pruett

Good morning Chris. Thanks for the fine report and your interest in your spot on commentary and lead in.

Chris Sighinolfi – UBS

Look at CapEx.

Steve Pruett

Yeah.

Chris Sighinolfi – UBS

I think that's an important distinction. Not something people pay attention to, but well, thanks for that Steve. Question for you, I heard at the end of your prepared remarks, but I missed it, the big delta between cash interest expense and interest expense on the income statement this quarter you mentioned a mark-to-market gain, I guess, re-list that, I mean what was that amount?

Steve Pruett

$2.1 million. It's one of the first – it's first time in the last three quarters that we had a gain on our LIBOR swaps. We finally have seen the LIBOR swap curve turn back around moving upward and so we realized our mark-to-market liability on our LIBOR swaps decreased from $14.2 million at September 30, 2011 to $12.1 million on December 31.

Chris Sighinolfi – UBS

Okay. Absent that, I mean, I saw long-term debt took down in the fourth quarter, we should just think about things sort of running on a normalized rate of what you guys saw maybe (rate)?

Steve Pruett

In terms of..

Chris Sighinolfi – UBS

In terms of the rate…

Steve Pruett

Expense, that’s correct.

Chris Sighinolfi – UBS

Okay.

Steve Pruett

Well, I say that in Q3, we had a MTM impact of about $0.5 million, so we want to back that out.

Chris Sighinolfi – UBS

Right, okay. And then as the borrowing base does get re-determined if you guys do make some acquisitions to earlier questions about, that's just a big asset. If you do start carrying a higher debt load into the future, would you look at adding to that swap position, I think you have around 360 swaps today if I am not mistaken?

Steve Pruett

Out of LIBOR swaps?

Chris Sighinolfi – UBS

Yeah.

Steve Pruett

Probably not, there’s always – we're on the threshold and our investment bankers including your colleagues are always encouraging us to consider terming out some of our debt with high yield, 8 to 10-year paper and given that possibility down the road that we are unlikely to increase our LIBOR swaps substantially. We did extend the term and added another $100 million of LIBOR swaps back in August and so we were able to reduce our overall cost and extend the term and add $100 million. So, I think, we are in pretty good shape for right now given our expectation at some point, particularly catalyzed by large acquisition of being able to and wanting to issue high yield debt.

Chris Sighinolfi – UBS

Okay. And then I guess finally just switching gears a little bit with some of the trucking delays risk you were mentioning and sort of the production that was offline that came back in January, were there associated costs with that we should think about as well or is that just the minimum?

Steve Pruett

No, that’s a good thought Chris. Last February in 2010 we lifted, I am sorry 2011, we had single-digit weather for several days and we had freeze-offs and we had severe backlog and we spent $0.5 million of incremental costs lifting crude that we weren't able to sell. Obviously, we look water in crude when we bring it to the surface and so we have that similar effect although it’s much more modest in Q4 than it was in the first quarter of 2011, but there is a cost for lifting those barrels that sit in the tank and don't get sold until a different period.

Cary Brown

Chris, I might mention, we did not have oil production shut-in in December or in Q4 due to the inventory builds. We just had an increase of stock in the tanks. That does impact our lifting costs because we paid the expenses to lift those barrels, as Steve mentioned, mostly water with a little bit oil that comes with it, but when we don’t sell those barrels that impacts your lifting cost accordingly, because you've spent the money and haven’t sold the barrels yet. I think you will see that workout in Q1. As Steve mentioned, we got that increase in inventory worked out and so we will have sold some barrels in Q1 that we didn’t pay the lift.

Chris Sighinolfi – UBS

Great, that’s sort of what I was hoping to hear. Well, nice job in 2011 guys.

Cary Brown

Thank you, Chris. Thanks for your support and your thorough research.

Operator

Thank you, sir. And I show no further questions in the phones at this time.

Steve Pruett – President and Chief Financial Officer

Very good. As always, I want to thank our research analysts for taking the time to peel the onion and decompose and recast our financials for investors and means at which they can thoroughly understand, perform an invaluable service to the retail public. We serve over 30,000 investors and most of which and many of which are in systems that you all work for and we appreciate all of our investors that are on the line and bankers that again have enabled our growth and have had confidence in us over the years and made Legacy the success it is today and I'd be remiss not to thank our employees and directors for all that they do the success we are just the spokesman representing them and we are honored to do so. Cary, do you have any closing thoughts?

Cary Brown – Chairman and Chief Executive Officer

Just say, really solid year 2011, I think we’re set up for a good 2012. Permian is a good place to be and our other basins in oily, so I'm just richly blessed and appreciate all your work. Steve did a great job working these guys. So, that’s all my comments. So, no further questions, we'll catch you guys next quarter.

Steve Pruett – President and Chief Financial Officer

Thank you. We're signing off.

Operator

Ladies and gentlemen, thank you for your participation in today’s conference. This does conclude the program and you may now disconnect. Everyone have a good day.

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