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Legacy Reserves LP (LGCY)

Q3 2011 Earnings Call

November 03, 2011 10:00 AM ET

Executives

Steve Pruett – President, CFO and Secretary

Cary Brown – CEO and Chairman of the Board

Paul Horne – EVP, Operations

Analysts

Kevin Smith – Raymond James & Associates

T.J. Schultz – RBC Capital Markets.

Ethan Bellamy – Robert W. Baird

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Legacy Reserves Third Quarter Results Conference Call. Your speakers for today’s call 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 remainder, this call is being recorded today November 3, 2011.

I would now like to turn the call over to Mr. Pruett.

Steve Pruett

Thank you, Mimi. Welcome to the Legacy Reserves LP’s third quarter earnings call. Before we begin, we would like to remind you that during the course of this call, Legacy management will make certain statements concerning the future performance of Legacy and other statements that will be forward-looking as defined by securities laws.

These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions. Actual results may materially differ from those discussed in these forward-looking statements and you should refer to the additional information contained in Legacy Reserves LP’s Form 10-Q for the quarter ended September 30, 2011, which will be released on or about November 4th, and subsequent reports as filed with the Securities and Exchange Commission. Legacy Reserves 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, Rocky Mountain and Mid-Continent regions of the United States.

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

Cary Brown

Thanks Steve and thanks to our friends and unit holders for joining us today. During the quarter of economic uncertainty and declining commodity prices, Legacy again produced strong results as we increased production and kept our expenses in line. To the end of October for 2011 acquisitions of producing properties totaled approximately $166 million of which $93.5 million of the acquisitions have closed and $72.5 million of acquisitions are scheduled to close prior to the end of the year. You may have noticed that these acquisitions are gasier than some we’ve done in the past. That’s not a function of pursuing gas per se.

We are an opportunistic buyer and gas is what is on sale today. And so we are able make acquisitions of gas properties without having to pay a lot for the additional upside locations that will get us, as gas prices recover and I believe they will recover in the future. We are still only about 20% gas by revenue, 80% of our income is still coming from oil. We are heavily weighed oil, so we had room to take opportunity as gas properties were on sale to buy some more gas and I am excited about what those transactions will lead to.

On the CapEx front. After a record second quarter, we invested $17.4 million in development capital, we invested $22.8 million in capital in the third quarter, in oil and in geo-rich drilling projects. An increase to our 2011 capital expenditures budget from $60 million to $72 million.

The results of operating Wolfberry program continued to exceed our expectations and we participated in an increase number of non-operated drilling projects that should generate attractive rates return.

We drilled our first horizontal Bone Spring wells in the third quarter, and I am very pleased with the earlier results. It won’t much impact on third quarter if any at all, but if it continues to hold up like the early results that are provided additional 0.5 to 20 drilling opportunities and we believe that CapEx – open up some CapEx opportunities for us next year and in the future if those wells hold up. So I am pretty excited about that. I will say that CapEx at current levels is definitely providing some organic growth. So we see that and we are excited about that.

Based on our quarterly adjusted EBITDA of $52.1 million which is the second highest in our history, we increased our distribution for the fourth consecutive quarter to $0.545 a unit. This will be paid on November 14. On a year-over-year basis, we’ve increased our distribution 4.8%. We’ve generated distributable cash flow during the third quarter of approximately $24.1 million or $0.55 per unit, covering our distribution 1.01 times. I will remind you that that’s with the elevated $22.8 million of CapEx we generally include all of our CapEx when we are looking at that. We know some of that is drilled CapEx and we’ll let you decide what that is.

For the nine months we generated distributed cash flow of approximately $79 million or $1.82 per unit, covering our distribution 1.13 times and again I will remind you that’s all CapEx including the growth CapEx that we are using.

I will now turn over to Steve to go over the numbers in details.

Steve Pruett

Thank you, Cary. We are very pleased with our third quarter results as we increased our production record levels, maintained our adjusted EBITDA at a high level during the period of declining commodity prices and we continue to produce strong drilling results.

Also we recently announced Wyoming and Permian Basin acquisitions totaling $72.5 million that includes calculated value of units. We are issuing about 278,000 units in one – in the Permian basin transaction that is a component of the $72.5 million. And these are expected to increase distributable cash flow per unit, provide additional positive momentum heading into 2012.

On September 30, our 13-member bank group increased our borrowing base from $500 million to $535 million, which was significantly oversubscribed. It’s a testimony to the health of the commercial banking sector for reserve base lending despite all the negative headlines about Europe. That borrowing base will automatically expand to $550 million upon the closing of our pending Permian basin acquisition that is expected to close on or about November 14.

The gas acquisition Wyoming was not evaluated by our banker because it was not visible at the time of our borrowing base re-determination.

At the end of October, we had a debt balance of $410 million, and that leaves us with approximately $125 million of availability under our credit agreement.

We are pleased to report unaudited preliminary financial information extracted from Form 10-Q which we’ll file tomorrow. I will make comparisons of the third quarter of 2011 to the second quarter of 2011 results. This information is contained in our earnings release. We encourage you to read all of that, along with our Form 10-Q which will be available in the Edgar system and on our website tomorrow.

So, I will now give highlights of the third quarter compared to the second quarter of 2011. Production increased 3% to 13,793 BOEs per day. We had a full quarter benefit of the acquisition in the Permian basin of natural gas assets for $66 million that closed on May 5. So we had a full quarter benefit of that in Q3.

Comparing the third quarter to the second quarter, production decreased by 1% and oil, natural gas production increased 13% and natural gas liquids production increased 8%. On a year-over-year basis, our quarterly production has increased by 41% which is a combination of acquisitions and organic growth.

Average realized prices excluding commodity derivative settlements declined 13% to $66.49. Average oil prices were also down 13% to $83.96 per barrel. Gas prices decreased 3% to $6.30 per MCF and average realized natural gas liquids price decreased 4% to $1.32 per gallon.

On average, realize natural gas prices are well above Henry Hub prices, they were favorably impact by the higher NGL content in our Permian basin natural gas particularly. And as you know NGL prices are strong relative to residue gas prices.

Oil and natural gas and NGL sales excluding commodity derivatives settlements were $84.4 million, down 9% from Q2. Production expenses excluding production taxes increased 5% to $22.1 million. That reflects an increased Well count and production from our acquisitions in drilling, as well as modest cost increases. However, production expense per BOE increased only 1% to $17.41 per BOE in the third quarter.

Legacy’s general and administrative expenses were $3.8 million or $3.01 per BOE, and that’s down from $4.5 million in Q2. cash G&A, that is backing up the non-cash comp expense that was only $6,000 during the third quarter and adding back our LTIP, cash LTIP settlement that were approximately $125,000, equates to $3.15 per BOE and that’s down from $3.55 of cash G&A in Q2.

Cash settlements received on a commodity derivatives portfolio during Q3 were $800,000 versus payout or a liability payment of $6.3 million paid during the second quarter. So relatively neutral contribution from our swaps and collars in Q3. However, they lag effect of settlement on our crude oil hedges was about $2.2 million and that’s basically caused by during periods of declining commodity prices, our cash hedging settlements for oil, fall into a month outside of the intended month of the swap, coverage if you will.

In Q3, 68% of our production was hedged compared to 71% in Q2. We reported an unrealized gain of $106.8 million on our commodity derivatives portfolio, due to declining commodity prices over the quarter. Our mark-to-market assets of our commodity derivatives portfolio is $56.9 million that compares to a liability of $49.9 million on June 30.

Adjusted EBITDA decreased 3% to 52.1 million from the record $53.8 million in Q2. On a year-over-year basis, our adjusted EBITDA increased 46%.

Development capital expenditures, as Cary noted, increased to a record $22.8 million, up from $17.4 in Q2. As announced on October 21, we increased our 2011 Development Capital budged from $60 million to $70 million which reflects higher working interest in our operated Wolfberry drilling projects, more non operated development projects and modest increases in drilling and completion costs.

Distributable cash flows for the quarter was $24.1 million and that equates to $0.55 per unit, a decrease was due primarily to the higher development capital expenditures as well as slightly lower adjusted EBITDA, slightly higher cash interest expense due to higher outstanding debt balances during Q3.

We generated net income of $125.1 million or $2.87 per unit in Q3, its higher production, higher commodity derivative settlements, lower production and lower ad valorem taxes, lower G&A, expenses contributed to that and mostly importantly the largest impact of the unrealized gain of $106.8 million on our commodity derivatives, and of course that all offset by lower realized commodity prices and slightly higher production expenses, and a $4.7 million impairment charge on our oil and natural gas properties.

Thank you for your continued support and confidence in Legacy’s employees and management and our board. We encourage to review our earnings release and read our risk factors and other more details disclosures on Form 10-Q available tomorrow.

At this time we would like to take questions.

Question-and-Answer Session

Operator

Thank you. Ladies and gentlemen (Operator instructions). Our first question comes from Kevin Smith of Raymond James. Your line is open.

Kevin Smith – Raymond James & Associates

Hi. Good morning gentlemen. Cary and Steve, would you mind trying to comment a little bit more on the horizontal Bone Spring well. Just wondering what that well costs and I believe you are entering an existing well bore. Do you think it would have been economic if had to drill the well bore and put in the lateral?

Cary Brown

Paul Horne is going to answer that, our EVP of operations is with us.

Paul Horne

You’ve got a good memory Kevin. We did drill that well out of existing well board, it reduced the drilling complete cost by approximately $2 million. We spent about $3.5 million and then anticipated grassroots will cost about $5.5 million.

Early results of that well suggest that we are going to have stellar economics out of the re-entry and we will still have very favorable economics drill in the grassroots well. So we are very pleased with early results. The well has been producing about 60 days now and so it’s early, but all results look very favorable, we are very pleased with it, we think it sets us up well for production rates in Q4 and beyond. So we are very pleased with it, Kevin.

Cary Brown

Kevin, Paul would be more specific, but we’ve been following the well for 60 days and we are about to run a sub-pump on it. So that should lift the production rate substantially, but we are not in the business of giving preliminary well information. But we will be prepared to talk about it later this year or certainly at the beginning of next year when we do our Q4 earnings call.

Kevin Smith – Raymond James & Associates

Got it. Just so too early to talk about the economics versus the Wolfberry and how that might compete?

Paul Horne

Yeah. We’re having that discussion daily as you can imagine here, but what I will say is with the cost that we spend on this well, about double Wolfberry well and then if we were to drill a grassroots well about three times the Wolfberry well. Suffice it to say that this well is producing in those ranges which suggests – and it’s currently blowing up casing. We don’t have tubing in the well much less the pump. So that suggests the well has significantly more capability than we’re currently realizing and it is currently flowing at rate in line with the multiple capital to the Wolfberry well. Also – because we’re in the middle of an existing field, we do have some other well bores in that field. Not sure, we haven’t looked and decided whether we’d go out of those or not, but we do have well bores in that field.

Kevin Smith – Raymond James & Associates

Got you. And then the other question I had before I turn it over. You’re hearing a lot of operators talk about drilling deeper in the Wolfberry and maybe even more so in the Spraberry area. Is there any opportunities for you guys to complete deeper formations in your Wolfberry program or how many intervals I guess are you completing in that and what does that look like?

Paul Horne

Yeah, it’s different, not from location to location, but area to area. The industry has lumped a very large area in and called it Wolfberry and so it really depends on what area you’re in and what area you’re drilling. We have drilled Wolfberry wells that have been completed through the Strawn. We have drilled Wolfberry wells that have been drilled through and looked at the Atoka as well and will be completed in the Atoka. But it strictly depends on where you’re at. If you’ve got to look at it on a very close regional basis to determine, you can really start destroying Wolfberry economics if you drill the well too deep and you don’t have good recoverable reserves in those deeper horizons. So the answer is yes, we do and yes we look at it in each individual area and we drill to the appropriate depths that we believe will recover economic reserves.

Kevin Smith – Raymond James & Associates

Okay. Thank you, gentlemen.

Operator

Thank you. Our next question comes from T.J. Schultz of RBC Capital Markets. Your line is open.

T.J. Schultz – RBC Capital Markets.

Hey guys, good morning. Good quarter. Just one of Kevin’s questions on the Bone Springs, I guess more related to the additional drilling opportunities. I think you said 5 to 20 additional drilling opportunities. Just kind of curious I guess one, what are those opportunities to existing well bores and versus grassroots and then kind of on the first well, it’s been on 60 days. At what point or where in the process do you get comfortable with moving forward in additional drilling opportunities?

Paul Horne

I’m really sorry. Could you repeat?

Steve Pruett

No, that’s okay. I could – T.J, we’re still – this is Steve. We’re still assessing our existing well bores. We do have some idle well bores, but it’s a complex decision as to whether the mechanical condition is adequate and whether there’s any other use. In the area that we drill, this lateral out of existing well, we already have vertical Bone Spring, second and third Bone Spring production. And so it was an established field and drilled by our predecessor. I think the Browns and McGraws acquired this field in 1999. We do have some acreage outside of this particular area which is called the Lee unit, but the number of locations is going to be driven by – primarily by industry activity offsetting us. There is a lot of activity that’s now establishing what the B factors are and the EURs, but we’re continuing to watch it.

We do have some restrictions related to drilling during Lesser Prairie Chicken breeding season. So we are going to have a required break from being able to drill up, but we’re assessing as Paul said our budget for 2012 right now and we want to build in the flexibility to drill one or two Bone Spring wells probably in the second half of the year after the breeding season is over and we can access our land. But we’re very excited about the potential land. We just need a little bit more time to establish the curve on our well and then particularly getting the electrical submersible pump down hole and look at the true potential of the well. But on a flowing basis it’s very, very strong.

T.J. Schultz – RBC Capital Markets.

Okay, great. Just jumping over to the Wyoming acquisition, I think it was on tribal land. Just curious how that process is going, and ahead of closing, any specifics there that you’re having to deal with or any surprises.

Cary Brown

One of the things that we did a few years ago was buy Iron Creek, and they have experience up there and that has led to this opportunity to be on this reservation. Tom Fitzsimmons who runs that organization up there has good experience. So we are dealing with those issues. We’re not seeing anything that is alarming or more difficult than we anticipated it would be. It is difficult, but if you’re a good neighbor they seem to be good guys to get along with and don’t see anything that would hold that transaction up.

Paul Horne

I will take that a step further, Cary, and say we’re very excited to build a relationship with them specifically. We believe there are additional opportunities on their lands and we believe Legacy Reserves can be a good partner that would partner with them to produce those reserves on their lands and we recognize their sovereignty and recognize that there are issues to deal with because of that sovereignty. But we don’t believe they’re issues that we can’t deal with appropriately, fairly and become a good partner with the reservation.

Steve Pruett

I might add, Paul is being modest, but in a prior life with a major oil company he was over a large field in southeastern Utah that was on tribal lands and did a very great – a very fine job of managing that relationship in that operation. And Tom has also got experience with tribal land. Tom Fitzsimmons, our Rockies business unit leader.

T.J. Schultz – RBC Capital Markets.

Okay, great. Thanks guys.

Operator

Thank you. (Operator instructions). Our next question comes from Ethan Bellamy of Baird. Your line is open.

Ethan Bellamy – Robert W. Baird

Hey guys. Good morning. Are there any more non-op Granite Wash interests we should be watching for and with respect for those ones that have already come in, were the declines commensurate with what you were looking for?

Steve Pruett

None, but based on the results of the three wells we participated in given the fourth location is co- located, I don’t think there will be a follow on well and that’s probably the most definitive answer I can give. If the operator doesn’t think there’s a viable location, we don’t think there’s another viable location unless it’s a different zone and a different approach because the initial rates were not what any of us expected. The declines are – they’re hanging in there pretty well. In terms of gas rates, the oil rates have fallen off really hard and it’s too early to say whether the wells will pay off, but it doesn’t look like to me they’re going to generate 20% rate of return. So how healthy is the potential in our business plan going forward.

Ethan Bellamy – Robert W. Baird

Okay. Thanks, Steve. With respect to the Permian Basin, what are the trends in service cost completions chemicals? Should we expect those to accelerate as we’re seeing all this unconventional development in Bone Springs and whatnot?

Cary Brown

We have seen increases in that area. We have also seen a great influx of iron into the basin, specifically in new drilling rigs. I am not anticipating significant increases in drilling costs. We have not seen the same relief on the completion side at this point and I would anticipate if the drilling continues at a pretty frenzied pace in the basin, there will be some increases in completion costs over time until that gets fixed. The good news is that the rates we’re currently paying for those services will justify new iron and a number of our service providers out here are working on that at a pretty rapid pace and we’re hoping they’ll just keep up and keep drilling and completion costs flat. I expect moderate increases over the short term.

Steve Pruett

And Ethan, I think a testimony that the pressure – it’s not only the iron, it’s the ingredients. A friend of mine runs Cudd, which is a frac company that’s a subsidiary of Rawlings and he’s been to India to look at – talk to their suppliers for ore beams which is the principal element of the gels, to Michigan and Canada for Ottawa sand and alternative mines for proppants. And there was one other component who was recently working. Of course we’re worried about water, less so today just since it’s got cooler. But that’s still a long term issue, but that’s our issue, not the frac companies. So the – and then labor costs. They continue to have a good supply from various sources where there’s underemployment. And so they’re working really hard to continue to provide our growing and serve our growing rig count. We’ve been very pleased with the performance and as Paul mentioned, the cost increases have been moderate, but we’ve got to keep an eye on all the inputs to the fracture stimulation process, from labor, iron and the ingredients.

Ethan Bellamy – Robert W. Baird

Thanks, Steve. Are you guys looking at any other new basins, any place to get a beachhead or still just focusing on bolt-ons and maybe more stuff in Wyoming specifically?

Steve Pruett

Yeah, we’ve got such a rich set of opportunities in the Permian Basin. I’d say if anything we’re looking at better positioning ourselves into place. We’ve mentioned the horizontal Bone Spring several times and we’ve been producing there for a long term on a vertical base. Now we have a horizontal, but we’ve also got acreage in the Wolf Fork as part of HBP rights on shallow production. Unfortunately not all of our Farmer Field area has the deep rights, but that’s in the Wolf Fork trend and we’re waiting for that trend to get closer to as we’ve had a lot of proposals for farm outs and we’re sitting on that for right now for it to become de-risk. We are looking at the Wolfbone play which is in Reeves and Pecos counties. Yeso, we got exposure to Yeso through HBP acreage and all of these places seem to be expanding and they’re getting de-risked. So it’s very much de-risk, but it’s expanding to the west. So that’s kind of the next way for us, the plays that I mentioned and we’ll dovetail those in to our capital program as they become de-risk. So it’s probably more of a 2013 impact than it is a 2012 impact on the plays that I mentioned up and maybe a couple of horizontal Bone Spring wells.

Ethan Bellamy – Robert W. Baird

Okay. And Steve, I’ve always assumed that if you guys use equity for an acquisition, that that’s going to pretty firm hands if somebody wants to keep the stock for a while. Is that accurate?

Steve Pruett

Yeah, that is. That’s definitely the case. We pride ourselves in utilizing on larger offerings, utilizing good retail systems that had good research support and wealth advisors that are looking after the best interests of their clients as opposed to a system that will just cram it out there and have it come back on to the market. And we’ve had a good record with our underwriting syndicate, a good retention and good placement and we hope to continue and maintain those relationships.

Ethan Bellamy – Robert W. Baird

Okay. Thank you.

Operator

Thank you. I’m showing no further questions in the queue at this time.

Cary Brown

Okay. Thanks guys for joining us today. It’s another good quarter and looks like we’re setting up lots of good things for the future and continue to be chasing acquisitions and I think we’re going to see more of those come as well. So hats off to the boys for what they’ve done and thanks for everybody joining us today.

Steve Pruett

Yes, thank you for your continued support. We particularly appreciate the equity research analysts that provide in depth coverage and for our partnership. We appreciate your questions and attention and support of the retail system to make our growth possible and we wish you all a great quarter. Thank you, Mimi.

Operator

Thank you. Ladies and gentlemen, this concludes the conference for today. You may all disconnect. Have a wonderful day.

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