Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Legacy Reserves LP (NASDAQ:LGCY)

Q4 2010 Earnings Call

March 3, 2011 9:30 AM ET

Executives

Steven Pruett – President, CFO and Secretary

Cary Brown – Chairman and CEO

Paul Horne – EVP, Operations

Kyle McGraw – EVP, Business Development and Land

Analysts

Kevin Smith – Raymond James

Bernard Colson – Oppenheimer

Ethan Bellamy – Robert W. Baird

Michael Blum – Well Fargo

Chad Potter – RBC Capital Markets

John Cusick – Wunderlich

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Legacy Reserves Fourth Quarter and Annual 2010 Results Conference Call. Your speakers for today are Cary Brown, Chairman and Chief Executive Officer; and Steve Pruett, President, and Chief Financial Officer. (Operator Instructions) As a reminder this call is being recorded today, March 3 of 2011.

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

Steven Pruett

Welcome everyone to Legacy Reserve LP’s fourth quarter and annual 2010 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 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, 2010, which will be released on March 4, and subsequent reports filed with the Securities and Exchange Commission. And we also refer you to our earnings release that’s available on various websites including Legacy’s site for greater discloser.

Legacy Reserves LP is an independent oil and natural gas limited partnership headquartered in Midland, Texas, focused on the acquisition and development of long life oil and natural gas properties located in the Permian Basin, Mid-continent and Rocky Mountain regions.

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 and unit holders for joining us today. After the challenges in 2009, Legacy experienced its most productive year to-date 2010. We grew annual production by, and adjusted EBITDA by 17%, and our proved reserves by 42%. In addition, we’ve closed approximately 280 million of acquisitions, including our two largest acquisitions, which established a new core area for us in the Rockies, and significantly expanded our Permian Basin asset base.

We ended 2010 on a high note, as we grew our production by 5% and our EBITDA by 11% compared to the third quarter. We continued to be encouraged by the results for our development drilling and working projects, which are meeting or exceeding our expectations. Our Permian acquisition only contributed 10 days to the fourth quarter results.

Due to our growth in 2010, and our positive outlook for ‘11, we increased our quarterly distribution to $0.525, paid February 14. We’re pleased to report in the fourth quarter even after detecting 13.6 million of development capital expenditures and prefunding our Permian Basin acquisition with issuance of additional units, we generated 21.5 million of distributable cash flow of $0.52 a unit, covering our distribution of $0.525 just under one time.

With the blessing of higher oil prices, we also have a few challenges that faces and one of the challenges is we have a lot of people that want to get in the Permian Basin, as they try to get oil in here. And we’re blessed to be here and as we see increased competition, we still feel like we’re going to be competitive. We’re glad to have places in Wyoming and other places that we can look if we Permian gets over value in our opinion. But, we’ve seen a good increase in our development drilling inventory. We’ll get lots to do, we’re going to up our budget to 45 million this year. And we’d always try to keep a three to four inventory of drilling on the books.

It looks like even with the $45 million budget, we’re going to have trouble keeping that inventory to three or four years, as we see more and more development opportunities on the assets that we purchased. So, all in all, I think we’re setup for fantastic 2011, and I’m very pleased with the effort that our employees give in 2010.

With that, let me turn it over to Steve and let him go over the specific numbers.

Steven Pruett

Thank you, Cary. We are, as Cary said, we are very pleased with our fourth quarter and annual results from 2010. Particularly the fourth quarter, we have a lot of momentum coming out of the fourth quarter into 2011. So as Cary said, we are very well set up for excellent performance in 2011. Our acquisition program during 2010 was fully supported by our bank group. We are able to use our revolving credit facility to opportunistically fund our acquisitions.

And our unit holders and equity underwriters supported us through two successful follow-on offerings, raising about $179 million after expenses. As of December 31, 2010, Legacy had approximately $85 million of borrowing capacity under our credit facility, and our, with our current $410 million borrowing base. After our recent meeting with our banker, we anticipate an increase to over borrowing base due to our newly acquired Permian Basin assets, the conversion of PUDs and probables to PDP categories and our reserves, our additional commodity hedges, and some other smaller acquisitions that contributed to the increased borrowing base.

We expect to announce this borrowing base increase along with an extension of the term of our credit facility in late March of this year. The strong performance in public capital markets and expanding credit facility, we are confident in our ability to fully fund our growth initiatives in 2011, including our acquisition aspirations.

With the full year contribution from our Permian Basin acquisition, which closed on December 22, and with the impact of our drilling programs, management of Legacy Reserves expects to be able to recommend further distribution increases in 2011 to our Board of Directors. And I’ll remind everyone the distribution increase in SAAR and the sole authority of our Board of Directors each quarter. We are pleased to report unaudited, preliminary financial information extracted from Form 10-K, which we will file tomorrow. I am going to make comparisons of annual 2010 results to annual 2009 results, as well as fourth quarter 2010 results to third-quarter results.

The information contained in our earnings release and for a more detailed disclosure, we encourage you to access Form 10-K tomorrow, and again look at our earnings release, which available on Legacy’s website. And our 10-K will also be available on EDGAR system. Highlights for 2010 include an increase in our reported reserves of 42%, 52.8 million barrels equivalent, of which 86% are proved developed producing. It’s one of the highest among or peer groups. And 74% are liquids, that’s predominantly and about 8% natural gas liquids. Compared, and this is an increase from 37.1 million barrels equal reported at the end of last year 84% PDP, 72% liquids.

Totally unit return, total unit holder return in 2010 was approximately 56.6%, of which about 46% was related to increase in unit price and the balance on cash distributions. The second highest in our peer group. We’re very excited for our unit holders stand for ourselves, a very good return in 2010. At the end of the year, or rather on December 22, we closed $101 million acquisition in the Permian Basin. That includes post-closing adjustments, and that’s the second largest in our history after the Wyoming acquisition, which we closed at February 2010 for approximately $126.5 million.

Partially to fund these acquisitions, we complete two equity offerings during the year, which required issuing 8.3 million units and raise net proceeds at a $179 million. We increased production year-over-year 17% to 9611 BOEs per day, and that’s primarily driven by those acquisitions I mention in Wyoming and also in the Permian Basin. As well as the results of major workover projects and development drilling.

Our oil production increased 30% year-over-year due to production from our oil assets in Wyoming and our oil focused drilling in the Permian. Despite these acquisitions, our NGL production decreased 15%, however our natural gas production about 3%. We had significant shut-in and downtime impacts in our, in our third party gathering and processing customer in the Texas Panhandle. That we believe in 2010 will not be as severe, but that remains to be seen. There is a major tight turnaround in the third quarter, which lasted about a month that was a severe impact. But we do see continued problems with gathering system in that system.

And with regard to our Permian Basin acquisition, it contributed only 10 days to 2010 results. We’ll have a full year impact of that in 2011, that’ll be a big boost to production and cash flow. Our sales from oil and natural gas liquids, and natural gas excluding commodity derivates where 216 million in 2010, that’s up 58% from a 137 million in 2009, which is the results of our increased production and higher commodity prices. Average prices were up 5% on a BOE basis at $61.68, that’s up from $45.73 per BOE in 2009, the bulk of that is from oil prices, which are up 29%, $74 a barrels from 57.40 in 2009. Average natural gas prices were up 30% to $5.76 per Mcf that’s realization, which includes the benefits of the NGL content in our wet gas, particularly in the Permian Basin. That compares to $4.43 in 2009.

And finally NGL prices were 39%, due to their correlation of oil prices, to a $1.6 per gallon in 2010, that’s up from $0.76 in 2009. Production expenses were up 22% on a BOE basis to almost 18 per barrel in 2010. It’s up from $14 and $0.76 per barrel. On an absolutely basis, the production increase is, increased primarily because of $8.8 million related to our acquisitions, primarily in Wyoming and Permian Basin. $1.1 billion increase related to workover activity. I am happy to report, we have very good results in the fourth quarter, third and fourth quarter, which related to a workover program in Reagan County and Irving County.

We had almost $1 million, onetime expenses related regulatory compliance, there is a new state wide rule 15 that was implemented in Texas January 1, but to get ready for that, we were very busy in the fourth quarter putting properties in the compliance. We also encountered production expanses from the other acquisitions we made and generally costs are rising and industry wide, particularly in Permian Basin related to the high level of drilling activity, which consumes a lot of ancillary services and certainly has an impact on labor costs.

Our SG&A expenses were $19.3 million or $5.49 per BOE on a GAAP basis that compares to 15.5 million or 5.16 per barrel equivalent in the prior-year. G&A expenses increased primarily about to $2.4 million increase in non-cash compensation expense. If you and then $700,000 of acquisition costs, which are now, considered G&A and $300,000 of one-time expenses related to the implementation of the BOLO system in house at Legacy, which went live in January of 2011.

If we examine cash to G&A, excluding the non-cash unrealized cost of the LTIP but by building in the actual cash settlements on unit expenses related to our long-term incentive plan, cash SG&A in 2010 was $4.59 per BOE compare $4.26 versus per BOE in 2009.

Now, I’ll turn to our hedging program results. Cash settlements on our commodities derivatives portfolio during 2010 were 20.1 million. That was down from 52.5 million we received during 2009. And we had very low oil prices and the gas prices. Our reporter production was 75% hedged in 2010 compared to 71% in 2009.

In 2010, we reported a unrealized loss of $21.5 million of commodity derivatives. That compares to a unrealized loss of 128 million in 2009, which was a staggering number. Remember, those losses are – we taking the mark-to-market defense in the mark-to-market positions that they – as the beginning of the reporting period in comparing to the end of the reporting period.

As a result of the increase in oil crisis over the year, our commodity derivatives, we had a commodity derivatives net asset position of 6.9 million as of December 31 of 2009 and that’s become a $14.7 million net liability on our aggregate commodity derivatives portfolio at year-end 2010. Adjusted EBITDA was up 17% to $140.4 million, that’s up from a 120 million in 2009. Our production volumes, higher prices were partially offset by lower commodity derivatives segments and higher production expenses.

Development capital is an exciting area for us to report on from 2010 and continues to be an area focus on 2011, an increased area of our focus. We invested $32.9 million in development projects on our properties that was up from $13.7 million in 2009. We presumed, we presumed an active development drilling program during 2010 special in the second half, where most of 69% of our 2010 capital was back end loaded or the second half of the year. We’ve greatly used our capital budget 2009 due to the financial crisis and low oil and natural gas prices. And most of those projects in 2009 were being on work hours in re-completion fact of non-operating drilling activities.

Distributable cash flow remained relatively flat over the period at $89 million dollars compared to $88 million in 2009, most reflective higher capital expenditures of $19 million higher than the prior year. Distributable cash flow per the unit $2.21 in 2010 that’s about 1.06 times coverage again reflecting the high-level of capital investment, which was benefit distributable cash flow substantially in 2011.

We generated net income, mind out with regard to that distributable cash flow per unit was impacted by pre-financing our acquisitions with unit offerings, equity offerings and not realizing all the benefit in those current quarters of the equity financing given that the acquisition is closed a month or so after the equity was issued. We believe that’s a put in practice though to make sure that we’ve got an appropriately levered balance sheet that we’re not over levered.

2010 we generated net income of $10.8 million or $0.27 per unit, substantially impacted by the unrealized commodity losses of 21.5 million the results of 37.3 million of mark-to-market losses on our LIBOR swabs along with 13.4 million of impairments charges in oil and gas properties. You simply add back the unrealized losses on the commodity and interest rate derivatives, we were close at a $40 million of plain earnings for just over a dollar per unit of adjusted earnings.

Turning now to the fourth quarter comparison to the third quarter. Production was up 5% sequentially to 10,337 BOEs per day that is not reflected on our run rate because the Permian Basin acquisition contributed only 10 days to quarter’s results. That compares to 9,804 barrels per day in the third quarter of 2010. Again we’ve got some impact from work hours in development drilling not all of which benefited the whole fourth quarter.

Average prices, our quarter-over-quarter increased $65.53 per BOE, up 12% from $58.51 in the third quarter. Oil prices were up 12% to almost $79 per barrel in Q4 compared to $70 per barrel in Q3. Gas prices increased 6% to 57.1 per NCF in Q4 compared to 5.40 in Q3, and NGL prices where up to $1.14 per gallon 19% over $0.96 per gallon realized in the third quarter.

Production expenses increased 21% on the quarter to $18 million on the BOE basis it was $0.14, excuse me 14% increase to $18.92 from $16.53 in the third quarter. Production cost were up primarily due to a $1 million increase and in workover activity, we talked about earlier $600,000 one-time regulatory compliance expenses and integration costs, primarily due related 15 in Texas. Production expenses from other acquisitions in the industry wide increase of cost of services.

Turning to G&A, reported G&A was 6.23 per BOE compared to 5.03 per BOE in the fourth and the third quarter. Converting that a cash basis, backing our unrealized electric effect, but adding in the settled unit compensation expense or the cash compensation expense, was 4.23 per BOE, quarter up from $3.73 in the third quarter.

Fourth quarter cash settlements on commodity derivatives $4.8 million from 6.3 million in the third quarter of 2%. We were 72% hedged in Q4 compared to 76% hedged in Q3. Over the quarter, we have an unrealized loss of 36.6 million on our commodity derivatives that was primarily driven by the dramatic increase of oil price over the quarter and an increase in natural gas prices as well.

Adjusted EBITDA was almost $40 million in the quarter up an 11% from 35.7 million in Q3. Higher production volumes, higher prices were partially offset by higher production expenses and lower commodity derivatives settlements. Development capital in the fourth quarter of 13.6 million related primarily to our workover drilling activity along with a lot of non-operated drilling activity as well. And given a lot of those benefits are spilling through the first quarter, were not fully realized in the fourth quarter. We had $9 million of capital – development capital expenditures.

Distributable cash flow $21.5 million down from 22.2 in the third quarter again related to the higher development CapEx. Distributable cash flow per unit of $0.52 in the fourth quarter down from $0.35 just shy of one-time coverage in the fourth quarter. Again, with the benefit of our Permian Basin acquisition at the year-end will be in better shape in Q1. And again we’re affected in Q4 by the unit offering which closed on November 18th; it’s about 3.45 billion units.

On an earnings basis, we generated a net loss of $18.7 million in Q4 driven by the $36.6 million of unrealized losses on commodity derivatives. We did have, that was offset by $3.5 million gain on our LIBOR swabs over the quarter and we had $900,000 of impairment on our oil and natural gas properties.

Again adjusting the loss for the unrealized losses on our hedges, commodity hedges offset by the gain on our LIBOR swaps record both adjusted net income is around $14.4 million around $0.35 per average unit outstanding during the quarter.

Again we want to thank all of you that are on the call for your interest towards Legacy. We greatly appreciate our investors which make our business plan possible. Relationships with our banks, our investment banks and particularly the research analysts how do such a thought job of covering Legacy. At this time, we would like to open the phone lines for questions.

Question-and-Answer Session

Operator

(Operator Instructions) And our first question comes from the line of Kevin Smith with Raymond James.

Kevin Smith – Raymond James

Good morning, gentlemen.

Steven Pruett

Good morning, Kevin (inaudible).

Kevin Smith – Raymond James

Yeah. Just had a question or actually one or two questions. First on your impairment charge, can you talk little a bit about that?

Steven Pruett

While the impairment charge for the year, for the quarter was very modest at a $100,000. That’s I guess what we’re mostly excited about. For the year, not prepared really to address all the elements of it other than there is a an impact given that we’re an active acquirer we end up, we’re evaluate properties in utilizing – Sorry. Prices at which we can hedge and when we end up running implement on the quarter we may utilizing a slightly different prices check on some occasions.

There is also some effect from new SEC related to PUG booking that can create some effects in that we can’t carry a PUG on the books beyond five years. We had a little bit of that. And we had a big impact in Q2. Again in a year-end impact was modest and that’s a good sign of help of the reserves but, in Q2 we had a big downdraft in gas prices. And wrote off some gas PUDs, not unlike the rest of the industry. So that was the largest effect for the year, given that’s a fourth quarter impairment was very modest.

Kevin Smith – Raymond James

Okay. And then, can you discuss maybe the weather impact on Q1 volumes as we’re looking forward enrolling our model?

Steven Pruett

I’m going to turn that to Paul Horne, our EVP of Operations.

Paul Horne

We were absolutely impacted in the month of February. Interestingly enough, in our operations where it’s coldest in the Rocky Mountains, we had very little if any volume impact. Simply because in that area, the operations are set up for the weather lately, we deal with on an annual basis. In the Permian, we’re just not set up for that because, typically we don’t have kind of weather that we had early in the month of February.

That was the second worst weather related impact I’ve seen in my career in the Permian. So it was significant for the month of February. I think it will have some impact at the quarter. I think the impact will be offset somewhat by the very pleasing results we’re seeing on our capital program, and pleasing results we are seeing with acquisitions, but there will be an impact in Q1. I don’t expect it to be hugely significant, I don’t think we’ll see negative coverage for the quarter, because of the weather impact, but I think it will show up in our numbers in the form several hundred barrels a day across the quarter.

Kevin Smith – Raymond James

Okay, that’s extremely helpful. And then lastly if I may, I know you guys had working interested in Granite Wash wells. What was the Black Trust wells that Lynn announced or which wells exactly were those?

Paul Horne

I don’t remember the numbers at the top.

Kevin Smith – Raymond James

Okay, so those are still, those results haven’t been publicly announced yet?

Cary Brown

That’s right, in fact we’ve got an update, that we’re still waiting – excuse me, Lynn is still waiting on fracture stimulation treatments in late March and early April on two of the wells and the third well, I believe Paul is drilling, I think it’s in progress now.

Paul Horne

Correct, for those that aren’t familiar, those are three wells, we knew when bought the congenial package that there were decent serendipity. This was a small interest in terms of value that we paid for and it came with unidentified PUDs. At closing we signed some Ages for three drilled wells. It’s about 10% of each one of those three wells that Lynn is drilling. So that was a nice serendipity, the congenial acquisition and we are hopeful that those drilling results will turnout as well as some of the other Lynn had up there.

Kevin Smith – Raymond James

Sounds good. Thank you for the time, gentlemen, and congrats on the strong year.

Paul Horne

Well, thank you Kevin, I appreciate that.

Operator

Thank you, sir. And our next question comes from the Bernard Colson of Oppenheimer

Bernard Colson – Oppenheimer

Good morning.

Cary Brown

Good morning.

Bernard Colson – Oppenheimer

Yeah, this is more of a, I guess a philosophical question, but and really wanted to see if you add some color around, how you think about cost-to-capital and EBITDA multiple that you are willing to pay for acquisitions. I know, in the past you’ve been pretty disciplined and had – I think average I saw was 5.5 times the EBITDA, on past acquisitions, but given that you could probably lock debt at six to 8%, and the yield being so healthy on the units. I was just wondering if how you balance those things or whether you are just taking a much longer-term from BOE and are not really willing to buy both some EBITDA multiple number.

Cary Brown

I have said that EBITDA multiple is not the driver in how we look at acquisitions. What we’re looking at is long-term sustainable accretion to our current unit holders. So if you run that out the shape of the curve on the strip has something to do with that. If you’re buying – today if you’re going to buy or while you’re going to be looking at $100 oil. So if you’re buying in that how much you will mistake on those that year is on. Already they’re continued to go up or go down. So we’ll run a – that we look at and say okay, over the next five years how accretive is this to shareholders and then over the next five years after that, what do we think it’s going to be to our unit holders.

So multiple of cash flow obviously is our cost of capital, cost of debt goes down. That is easier to be accretive, but it really you got to look at the kind of decline you’re buying and you manager (inaudible) think you’re going to get on the assets you’re buying and what you can hedge and what you think the prices after you hedge. So all that’s going to lead to – I will tell you when you get past seven times cash flow, you better have a lot of confidence in your deployment and you’re going to be destroyed value for your shareholders. That’s what we see most of the time now. That’s kind of a long when it hedge or two, we look at every acquisition, if we think it’s accretive to our unit holders over the long we tried to buy them.

Steven Pruett

Cary, I really appreciate your comment about the long-term. And we do think, as Cary motioned we do think about long-term accretion wealth. We’ll think about long-term cast-off capital. We believe, we’re in a bit of a bubble on the search for yield and we can’t count on these kinds of yields or potential debt yields, if you will forever, something with bank prices or bank interest. We won’t have 25 basis points on LIBOR forever.

So would you take our longer-term view of our cost of capital, that’s a prudent side? We haven’t shifted our view of our cost of capital, because of the recent run-up. We believe that investors with the guidance from people and yourself and your peers are expecting distribution increases from the multi sector and that’s part of the reason we’ve tried it inside of 7% and some of the pipelines are in the – have a 4% plus yield is expectations of distribution growth.

So we’re not going to change our stands because of that. Now we have as Cary mentioned, (inaudible) robust work on oil prices in particular, because the shift in the market. And we still have a tale price or an un-hedged price; it’s well below where the current strip is. But we can certainly pay more based on being able to hedge forward, right now what’s the, North of a $100 per barrel. That helps bridge the – spread particularly with private sellers who don’t have access to hedging like we do.

Bernard Colson – Oppenheimer

Right. Okay, that’s extremely helpful. And I guess specifically on the Permian, the competition – is it primarily from traditional players that are just willing to pay more these days or you see any real intellects of new buyers there?

Steven Pruett

I’ll turn that to Cary – Kyle, do you want to address that? Our EVP of Bus Dev.

Kyle McGraw

Yes, I’ll comment on that.

Steven Pruett

Okay. I

Kyle McGraw

I know in recent transactions, we have the intelligence. We think we’re, when our fellow MLPs required once. So that’s a long-time party. I know of a recent private company, we understand. Block, as they had money in the bank and so, with their yields that we’re getting on their interest rate, at what interest rates we’re going to cost them, they were willing to step up on a property that they believed in the up side.

So we’re seeing all types, I do know they are startup private equity groups that need to make a name for themselves. They need to make a name for themselves. They need to find something of, so they are their competitors on transactions. We don’t often compete for the same kind of properties that require higher upside. A greater percentage of PUD that we do that they are a lot of competitors, however they’ve always been in competitor side. We never looked at a deal that, that weren’t any of the competitive process. And so we think we still get our share.

Bernard Colson – Oppenheimer

Okay, and then (inaudible) on the really low, kind of the (inaudible) into that range where you got kind of five to, call it $20 million kind of deal. I mean are you still seeing more competition in that area as well or is that a little more insulated just given the size?

Kyle McGraw

Well, I do think it’s our little more insulated given the size. The deals that are in the $200 million range, it represent a lots of Permian properties very oily. Those are highly competitive and the metrics team to show that. Yeah, we think the smaller transactions seem to be a little better and yet still they’re, there is still always competition but that doesn’t seem severe.

Bernard Colson – Oppenheimer

Yeah, okay. Thanks a lot guys.

Steven Pruett

Thank you, Berny. One trend I’ll mentioned that’s been beneficial and fill in a very small end but following our year-end acquisition from Concho, we’ve had the number of working interest partners in some of the Concho operated wells that have called us and said (inaudible) similar metrics and of course we’re very happy to since oil prices have moved up. So we’re very responsive to the opportunities to roll-up additional interest in properties that we already operated our own significant interest in.

Operator

Thank you. Our next question comes from the line of Ethan Bellamy of Robert W. Baird.

Steven Pruett

Good morning, Ethan.

Ethan Bellamy – Robert W. Baird

Good morning, gentlemen. Couple of questions for you. Steve, what (inaudible) reserves be performed a day for a $100 strip? And how should we think about that based on price revisions going forward?

Steven Pruett

That’s a great question. We’ve not done that sensitivity all though, certainly we have corporate models that around the various price sensitivities we don’t really look at our reserves SEC ‘10 or excuse me, that would not be SEC ‘10 but on a flat price basis, of that we haven’t done that recently. But we’ve done – certainly done that in the past. So I don’t have a good answer for you. But certainly given the long live nature of our reserves $10 price increases basically adding tale reserves, those some had as much PV significance is the near term reserves that could certainly the price spills that has a huge impact on Legacy’s reserve value. I’m sorry, I don’t have an answer for you on that one.

Ethan Bellamy – Robert W. Baird

It’s just ballpark, should we be thinking, probably not a linear but, half the price change equates to reserve adds on the same level?

Steven Pruett

Well, I couldn’t speculate is to that. But it remains me we have an upcoming board meeting recently. We’ll probably do that – performer that sensitivity. So we just haven’t done it yet, I couldn’t respond accurately.

Kyle McGraw

Yeah, I’ll...

Ethan Bellamy – Robert W. Baird

All right, fair enough. I know, I had asked you, not Cary.

Steven Pruett

Reason I...

Ethan Bellamy – Robert W. Baird

So, this $100 oil open up any probable or prospects that you probably wouldn’t otherwise consider. And is there some debt color form out that you might be able to employ to pull that value forward cash flow – bring you on a sustainable production treadmill?

Steven Pruett

I’m actually pretty excited about our growth and our absolute growth and the growth in our EBITDA, such that, we’re able to grow our development capital budget. I know, Paul and his team are very excited to scale up to continue drilling program. And we’ve got a very – just say we spent some time with Thomson Simons our Wilmington business unit leader, who is with us this morning.

And his with colleagues up and Cory reviewing some Rockies projects there is a lot of potential up there. And we’re jealous of retaining all of that PV10 or NPV 10 from our development inventory and down a – we hope that continued growth will enable us to accelerate and of course Paul a great of job of high-grading our development inventory and we’re very excited about the self-developing – and I mean, not deleting a buffering again a third party partner. But when it gets higher risk out there we have in the past employed foremost Kyle has been very good about finding partners of partners find us and propose something it’s little too while for us and so called we’ve done some (inaudible). We’ve got any form outs in the tale order at this point of time.

Kyle McGraw

Non-significant, yes, that is some little, little proposals that are out there they would be significant. Answering to the first half of that question, the $100 role, definitely changes the economics on a number of our projects. We don’t have a lot of projects for our PNDPs that are uneconomic at 80 and I will make at a 100, but it is absolutely can swing the economics and make projects more favorable, especially if we start comparing all projects against projects that, obviously the old projects just continued to look significantly better than gas opportunities. In the main areas, where you may be developing less reserves in spite of the value on for BOE basis of those reserves. There can be changes in priority.

Cary Brown

One thing we’re seeing each in is, our neighbors are started to do lots of horizontal drillings in oil plays. We historically had not done that; very often we have done some horizontal drilling a lot. So we’re watching that in and around it. And just about every one of those plays its going horizontal; we get acres, some of a more significant than others. But as prices stay high and we did some data points we could add some significant reserves, just going horizontal on our current acreage if those plays turn out. We’ll see – but we’re watching those pretty close, it’s kind of an interesting development at here.

Steven Pruett

That’s a great point Cary that the, a larger portion of our budget is non-operated drilling activity and has financially benefit. One they’re creating value, and – and fairly they are proving up some trends offsetting us and offsetting leases we operate. And the that industry activities, has been very supportive of our future value and proving our inherent value in all leases that we’ve had even predating Legacy back to the brothers (inaudible). It’s exciting to see in the Permian Basin in particular.

Ethan Bellamy – Robert W. Baird

Going to back to Wyoming, would you guys ever step up and drill a CO2 pipe yourself or you’re going to be oiling on others to provide supply for something like that?

Cary Brown

We’ve got to pipe running through one of our fields (inaudible) their line to Beaver Creek virtually runs through the field. We’ve had a lot of joint-venture discussions, and if you note on Cary’s – that’s you’ve got yet another person that composition him for few two joint ventures we probably had 5 or so parties approach us and that would be the most logical step as a joint-venture where somebody to accelerate. We certainly have the skill settings on our Legacy’s just the cash out, three years of cash out before you turn cash positive, maybe 4 years of 5 years and that’s not very suitable to in MLP.

Kyle McGraw

It’s not right now, as we get larger, just like you saw a built from a small driller and now we will run at one rig, as a drilling rig, we can look at longer term projects. And that’s being – what we’ve done of far, is we’ve kept those opportunities in housing and there is going to be a day, we need those – and where now instead of forming – had plans two years ago.

We’re now drilling at Marcellus. You may see us get to the point where we think is CO2 is the right answer. Today that’s not where we are in terms of what we think it is the right for us to do on our assets. We still have some assets that letting them to CO2 and with that trade where it is, it’s hard for me to see somebody that’s going to have a better position to capitalize than we are, to develop for that self. Every day we come in and we ask the question, how we’re going to develop value for our unit holders and we tried to have an open mind as to what that looks like.

We were very pleased to have a data said today, that say’s may we get some great places it’s been capital and our employees have been very good at identifying additional places as those opportunities come along. So we feel very healthy and feel very good not really – you’re looking pretty hard at developer and at this point, we’re not seeing that as the primary way we’re going to add value to those – there is some ideas we have on an acquisition that we might need to speed general development up to make an acquisition. But our own assets, I think we’re going to do most of that development you.

Steven Pruett

Well, Cary makes an interesting point that larger MPLs like Kinder Morgan and enterprise take on multi-year projects and kind of what put a box around that growth initiatives and finance it. And the analysts are very comfortable with, even though if you roll it in that CapEx multibillion-dollar CapEx over several years that might employee negative coverage.

And we do have a unique low cost of capital even these are the companies like Devon. And we do have the skills internally with CO2 and other tertiary experience from the likes of Mobile and Marathon, or Comico and others that are in-house. So it’s not a matter of lacking the technical. Our operational capabilities we’ve got good access to capital. I think it’s more of being knowing when the right time is to do it and being able to position it probably among the investment community and particularly yourself and peers to explain the long-term benefit it would have for our unit holders.

Ethan Bellamy – Robert W. Baird

Thanks, gentlemen. Good luck.

Steven Pruett

Thank you, Ethan.

Cary Brown

Thanks for the good questions.

Operator

Our next question comes from the line of Michael Blum of Well Fargo.

Michael Blum – Well Fargo

Hi, good morning.

Steven Pruett

Good morning, Michael.

Michael Blum – Well Fargo

Just two real quick ones from me. One – I was wondering if you could – can you any kind of mention you’re starting to see cost pressures from higher prices. Can you kind of put a pencil to the paper on a little bit? And a little flavor in terms of quantifying what that – where exactly those pressures are coming from other than Labor and sort of percentage wise, how should we think about that?

Steven Pruett

Yeah, you got to look at a couple of issues. One, when you look at year-to-year increase and lifting cost not absolute value, it just doesn’t make sense in an acquisition phase, we hit rocket MPL to look at an absolute basis. But on a lifting cost basis, year-to-year we had a significant increase and a large part of that was very expected. When we made the Wyoming acquisition, we recognized that those assets, where in the excess of $20 a barrel lifting cost.

We take that into our acquisition, we’ve planned on that. So as you make an acquisition it has significantly higher lifting costs than you base, obviously that’s going to increase the overall. We’ve really didn’t see any significant surprises on a year-to-year increase.

When you look quarter-to-quarter Steve mentioned a number of aspects in the quarter-to-quarter increase. We’ve absolutely seeing an increase in the lifting cost. As all prices rise, you can expect that to continue. If all prices were to drop, you see a reversal of that. We’ve tracked that pretty closely not only overall just a little bit over our careers and it’s very correlative. So the real key with lifting cost is, watch your price outlook. We had some specific things in Q4 that Steve mentioned. We spent at about a $1 million in increase and workover activity. Obviously as prices increase, then the desire to go out and work on wells and increased production increases dramatically.

So we intentionally increased our lifting cost on a short-term basis, because of increase in prices and then of course you had the pressure from a record rate number of drilling rigs running in the Permian, which you think that only affects drilling rigs, but it affects all of the ancillary goods and services. And then, electricity cost is so directly tied to energy cost that we’ll see an increase in our electricity costs as well.

I don’t know if that answer to your question specifically, but that’s kind of what we’ve seen from not only the year-to-year increase but also quarter-to-quarter increase.

Kyle McGraw

Michael, I would say, Cary and I are very careful not to beat on Paul and his team about lifting cost too much. We’re in the cash flow business and it’s all about maximizing margin and this environment as being the oil production business primarily and associated in NGLs, associated gas the more volume we can produce and nearly all the volumes are bringing online incrementally, generally high margin. And it’s time to catch your incremental barrels not beep people over the head on cost, not I thought to say, we don’t bid our vendors and keep them honest, but it’s time to be active and put oil online rather than trim cost just to check just to have a better metric on the on the cost side.

Michael Blum – Well Fargo

Okay, that’s helpful. And my second question was just around infrastructure and take-away capacity constrains in the Permian. I guess we’re starting to hear a bit of that from the midstream players. And I’m curious, you know if that’s a concerns you in terms of being able to get your sufficient take-away, you get from your products to market?

Steven Pruett

It’s certainly a concern Michael, it has impacted us directly in the Permian, yes we are told by consultants and our partners and peers that are coming. We’re aware of the given others that made us worth 15,000 barrel a day expansion on the Basin by pipelines, by playing some west Texas Cushing. We rather have more pipeline capacity down to the Gulf Coast and we understand there is some discussions in the works, potentially with our Millennium or perhaps enterprise we’ll make a move there, because we’re seeing increasing volumes out in the Permian from the Wolfberry and prospectively from the bunk spring envelop show in the whole developments out to the west.

In the Panhandle we have had some constraints and had some inventory buildup and our tanks and that’s being (inaudible) we’re told they prefers with some increased pump capacity installed by Bolero from again from Panhandle over Cushing. So everything seems to – Cushing which is why we got a or we told why we got a $15 to $20 difference between Cushing and brands or even LOS. So we are very hopeful that the market giants, Millennium and enterprise and even more Kinder Morgan or others take advantage of these big Arbitras from watch Texas to the Gulf Coast.

Cary Brown

The BOE, Michael, is that we’re hit our pure hedge. We hedged WTI, so even though there is differential between WTI and Brant, our hedges are still based on WTI. So our cash flows managed based on that. We don’t like that differential to go away, we expect that those guys will fill the pipe capacity or turn – we’re at I guess 9,000 barrels and they come out in the Permian, and I think we were close to 1.5 day at point, Steve...

Steven Pruett

1.2 million over due.

Cary Brown

... 1.2 million over due. So the pipes are they’re, they just got to turn around and somebody will solve that problem. I believe it’s solvable, because it is over the past, they will figure that out. So it’s not something that we’re only concerned about, we’d like them to figure out quicker. So that our differentials of rate would go away.

Steven Pruett

Believe me, we’re keeping our finger on that whole stone though and engaging some telecommunications so we’re aware of what’s coming and can plan accordingly.

Michael Blum – Well Fargo

Thank you very much, gentlemen.

Steven Pruett

Thank you, Michael.

Operator

Thank you. And our next question comes from the line of Chad Potter of RBC Capital Markets.

Chad Potter – RBC Capital Markets

Good morning, guys.

Steven Pruett

Chad.

Chad Potter – RBC Capital Markets

Just given the strength in oil prices, I know it’s just been a few months since you touched your 2011 budget, but given the strength of oil prices, and the opportunity you said that you have before. What are your ideas about potentially going to the Board to increase your 2011 CapEx budget?

Cary Brown

Chad as you may recall, we said our $45 million project back in November and that was prior to closing the Permian Basin acquisition on December 22. Where it certainly provides more cash flow, it’s a part of some additional properties since then. So that provides additional cash flow that given the robust oil price environment with the great inventory we have, gives us the opportunity to plan more back in the ground. So I would expect in the near future, the capital expenditure or capital budget increase would be forthcoming in the near future related to that extra cash flow and that deep project inventory which are Board has been very supportive and it’s excited about our development drilling activities as we are.

Chad Potter – RBC Capital Markets

And would you, think about potentially adding a second continuous rig to the Wolfberry or would the incremental capital be more devoted to workovers in those other areas?

Paul Horne

I wasn’t anticipating a second Wolfberry rig at this point. You heard Cary and you heard Steve say our one rig program but at any given time, this year will have two, three possible even four drilling rigs running. We just pick up our rig to drill 3 or 4, 6 or 8 wells in this area, we probably going to have a rig running in Wyoming at some points in hopefully the second quarter. And that’s what I would anticipate the at least the request that we’ll make to Board will be is to allow us to do some of that work. And we really noticed a significant increase and non-off CapEx from our non-off partners. And I think we’ll have a – we’ll make the request increase our capital budget for some of those firms as well.

Steven Pruett

Yeah, Paul right if we don’t increase our budget, will have trouble keeping up with some of our outside operated activities. In some cases, we own 50% or even greater of some drilling opportunities. There is a rig running North of town, North of Midland where we got 50% interest and we got to keep up with that, it would be sad to go non-consent on something that’s so attractive. We will not to stats to go not to concern on something which so attractive. We will not put ourselves in a position to do that. And we want to able to stay committed to this Wolfberry drilling program that we’re operating and having great results on.

Chad Potter – RBC Capital Markets

I appreciate the color guys. Thanks.

Steven Pruett

You bet Chad. Thanks for the question.

Operator

Thank you. (Operator Instructions) And our next question comes from (inaudible).

Unidentified Analyst

Questions have been answered, thanks.

Steven Pruett

James, you on the West Coast this morning or East?

Unidentified Analyst

East Coast.

Steven Pruett

All right.

Unidentified Analyst

Freezing.

Steven Pruett

Good. It sounds lovely. Hope it’s a long winter up there and you need to work up some of this excess cash.

Unidentified Analyst

Yeah, I don’t know if we’re going to do that, up here though for you.

Steven Pruett

Sure.

Unidentified Analyst

But my questions have been answered.

Steven Pruett

Oh, very good James. Good to hear from you.

Operator

All right. Thank you, sir. And our next question comes from the land of John Cusick of Wunderlich.

John Cusick – Wunderlich

Hi, good morning. Given all the positive news as far as they commodity price environment and the recent acquisition and the borrowing base redetermination. Would you guys be willing to sort of talk about what coverage ratio you are comfortable with in over the long-term?

Steven Pruett

Well, we’d like to given that we’re upstream NOP, we do have a great hedge position and expect to remain committed to that. We have a hedging policy that’s got a five-year tail on it. We hedge our acquisitions. But, in general we’re trying to target 1.2 times coverage to the extent that we’re going below that as we did in 2010. It was related to specific growth initiative.

In this case, development drilling. We’ll have some of that in 2011, but expect our coverage to move up, move North from the 1.06 times that we saw in 2010, which was kind of transition, we’re coming out of a very low oil prices and ramping up CapEx in 2011 ought to be more stable, typical year yet with an aggressive development program, still trying to get to close of that 1.2 times coverage.

Again we talk about coverage, John in the contest of throwing all of our development capital and deducting all of that from our EBITDA if you will where some of you, analysts backout growth capital and we certainly encourage that. But we’re not in the business that sort of dissecting what among our development inventories growth versus maintenance. I know that’s a classic questions, I am surprised Ethan didn’t ask it today, because I never answer it very well.

That’s still a long (inaudible) we think we do need about 1.2 times coverage given the volatility of commodity prices despite being heavily hedged in the first two years. And would, the other aspect of that covers the enterprise where our debt levels are there kind of two times debt-to-EBITDA, and if we save, pull it 2.5 times that’s comfort zone for us. If you got closer to three times, as some of our peers will – couple of our peers are, then that might impact or cause a need for higher coverage.

John Cusick – Wunderlich

Okay, thank you.

Steven Pruett

Thank you.

Operator

Thank you, and I see no further questions in the queue at this time. I would like to turn the call back over to Mr. Brown and Pruett for any further remarks.

Steven Pruett

Thank you, and again, thank you for the fine questions and the attention, and of course the excellent research that each of you provided to your, for Legacy, for your investment clients. We look forward to reporting again in May. I think we are set up for a fantastic first quarter, and we wish all of you the very best. And again, appreciate the support of our investors, analysts, and bankers, and our investment bankers.

Cary, you have something add?

Cary Brown

Nothing, thanks, guys.

Steven Pruett

Very good, take care.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Legacy Reserves CEO Discusses Q4 2010 Results - Earnings Call Transcript
This Transcript
All Transcripts