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

Legacy Reserves Lp (NASDAQ:LGCY)

Q2 2012 Results Earnings Call

August 2, 2012 10:00 AM ET

Executives

Cary Brown – Chairman, President and CEO

Jim Lawrence – Interim CFO, Vice President, Finance and Treasurer

Paul Horne - Chief Operating Officer and EVP, Legacy Reserves GP

Analysts

John Ragozzino – RBC Capital Markets

Ethan Bellamy – Baird

Kevin Smith – Raymond James

Praneeth Satish – Wells Fargo

Bernie Colson – Global Hunter

Chris Sighinolfi – UBS

Michael Peterson - MLV & Co.

Operator

Ladies and gentleman, thank you for standing by. Welcome to the Legacy Reserves Second Quarter Results Conference Call. Your speakers for today are Cary Brown, Legacy Reserves Chairman, President and Chief Executive Officer; and Jim Lawrence, Interim Chief Financial Officer, Vice President, Finance and Treasurer. At the 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, August 2, 2012.

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

Jim Lawrence

Welcome to Legacy Reserves LP’s second 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 would be forward-looking statement 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’ Form 10-Q to be -- for the quarter ended June 30, 2012, which will be released on or about August 3rd and subsequent reports as filed with Securities and Exchange Commission.

Legacy 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 conference over to Cary Brown, Legacy’s Chairman, President and Chief Executive officer.

Cary Brown

Thanks, Jim, and thank you to our friends and unitholders joining us today. It was an interesting second quarter for us. Good operational results and strong acquisition efforts were over showed by several factors that negatively impacted our adjusted EBITDA.

We saw swing from high in the first quarter to the low in the second quarter approximately $30 in oil prices and that create some usual things that look little different for us.

Due to WTI average oil prices of approximately $106 in March and $82 in June, we had an unusually large negative oil lag effect about $5.2 million burdened our adjusted EBITDA on second quarter.

In addition, our realized oil price in the second quarter were impacted by increased average oil differentials, we saw the Permian and Midland-to-Cushing differential with all to about $5, historically that’s been about a $50. Those are -- that’s a space where we are unhedged and gave us little bit concern, we are happy to report that it already back inside of what it was back to the norms in the first quarter.

So it’s down from $5 differentials on oil Midland-to-Cushing to about $50 or even inside that. So that could have been the long-term impact. It was a short-term impact affected us in the quarter. Also saw some issues around Wyoming differentials but those were also coming back.

These factors combined with the impact of falling commodity prices on the portion of our quarterly production that was unhedged were the primary contributors to our decline in adjusted EBITDA from the first quarter to the second quarter.

On a positive note, we think those are short-term issues because the refineries are backup until one of those differentials are back to normal.

On the acquisition front, we closed seven acquisitions of producing properties for about $105 million, we believe to be highly accretive, including our acquisition of oil properties in North Dakota and Montana, these are new states for us, we are growing at Rocky Mountain division and feel good about being up there.

Our $105 million of acquisitions in the second quarter makes that one of our strongest quarters ever and our best since the fourth quarter of 2010 on acquisitions. The production from these acquisitions along with several successful workovers in Wyoming and Permian Basin helped keep our production relatively flat during the second quarter despite not drilling any of our operated Wolfberry locations during March and April.

In addition, we continued to keep expenses in line and made larger than expected investments in some several attractive non-operated drilling projects in the quarter.

Overall, the performance for the first half of 2012 was strong, as we generated $95 million of adjusted EBITDA and $55 million of distributable cash flow. We look forward to realizing the full impact of our acquisitions during the second half of 2012, and we feel good about our pipeline of potential acquisitions and our inventory of development projects.

Based on these results over the first half of ‘12 and our positive long-term outlook, we increased our quarterly distribution for the seventh consecutive quarter to $0.56 per unit, which was paid on August 10, 2012. Since the second quarter of 2011, we have increased our quarterly distribution about 3.7%. So, all in all, we feel really good about where we are.

On slide might be that first quarter was as good as, it might look, and the same quarter is not as bad as you look, but when you look the full half -- first half of year and you look those results will run on track with where we expected to be and with continued commodity prices in this level, we see good things for the rest of the year.

With that, I’m going to turn over to Jim to go in more detail into the numbers.

Jim Lawrence

We are pleased with our results and our strong acquisition efforts during the first half of 2012, as we expect our $107.6 million of acquisitions of producing properties during the first half of 2012 to be immediately and long-term accretive to our distributable cash flow per unit.

On August 1st, our debt outstanding under our credit facility was $432 million, leaving us with current availability of $133 million. Our current borrowing base of $565 million was redetermined by our 14-member bank group on March 30th, and their redetermination calculations included none of our $107.6 million of acquisitions of producing properties.

Our next scheduled -- our regularly scheduled bank group meeting is in September and we expect to have our revised borrowing base including our acquisitions on or around October 1st.

We are pleased to report unaudited preliminary financial information extracted from our Form 10-Q which we will file tomorrow. I will make comparisons of second quarter 2012 results to first quarter 2012 results.

This information is contained in our earnings release and for a more detail disclosure we encourage you to access our Form 10-Q which will be available in the EDGAR system and on our website tomorrow Friday, August 3.

Production decreased 1% to 14,297 Boe per day in the second quarter from 14,440 Boe per day in the first quarter. As previously discussed, to stay within our $62 million capital budget and still develop a few of our locations in emerging plays, we chose not to drill any of our Wolfberry locations during March and April.

In addition, due to the normal time lag involved in the drilling and completion process, we did not have any production during the second quarter from our Wolfberry wells that we drilled in May and June. Accordingly, our second quarter production was negatively impacted by the significant natural production declines associated with our Wolfberry drilling, which provided strong initial production rates during the first quarter.

Due to our drilling delays, these production declines were not offset by new initial operated production during the second quarter. In addition, high pressures in natural gas gathering lines in the Permian Basin during the second quarter that were caused by normal plant maintenance downtime and extensive development in the area also contributed to our production decline.

These factors were largely offset by production from approximately $107.6 million of acquisitions of producing properties during the first half of 2012, including our acquisition of oil properties in North Dakota and Montana for $69.3 million that closed on May 23rd, as well as production from several successful workovers in Wyoming and the Permian Basin.

Average realized prices, excluding commodity derivatives settlements, were $60.85 per Boe in the second quarter, down 14% from $70.51 per Boe in the first quarter. Average realized oil prices decreased 14% to $83.27 per barrel in the second quarter from $96.62 per barrel in the first quarter, as our realized oil prices were impacted not only by a decline of approximately $9.70 per barrel or 9% in average WTI crude oil prices during the second quarter compared to the first quarter, but also by an increase of approximately $3.65 per barrel in the oil differentials during the second quarter.

These increased differentials were primarily driven by a Midland-to-Cushing/WTI differential that averaged approximately $4.90 per barrel in the second quarter compared to approximately $1.50 per barrel in the first quarter, or an increase of $3.40 per barrel.

As the refinery downtime issues that were the primary cause of the increased Midland-to-Cushing differential were alleviated, this differential narrowed back to first-quarter levels during the end of the second quarter and early third quarter. In addition, realized natural gas prices decreased 20% to $3.87 per Mcf in the second quarter from $4.81 per Mcf in the first quarter.

And average realized NGL prices decreased 9% to $0.97 per gallon in the second quarter from $1.07 per gallon in the first quarter. Our average realized natural gas prices are favorably impacted by the NGL content in our Permian Basin natural gas.

Oil, NGL and natural gas sales, excluding commodity derivatives settlements were $79.2 million in the second quarter, a decrease of 15% from $92.6 million in the first quarter due to slightly lower production and significantly lower realized commodity prices per Boe. The increased oil differentials during the second quarter decreased our revenues by approximately $2.9 million, including approximately $1.9 million attributable to the increased Midland-to-Cushing differential.

Production expenses, excluding taxes, increased 4% to $23.9 million in the second quarter from $23 million in the first quarter due to production expenses associated with recent acquisitions. Production expenses per Boe increased 5% to $18.35 per Boe in the second quarter from $17.49 per Boe in the first quarter.

Legacy's general and administrative expenses were $5.2 million or $3.97 per Boe during the second quarter compared to $6.5 million or $4.91 per Boe during the first quarter. This decrease was primarily due to lower unit-based compensation expense, which decreased to a benefit of approximately $24,000 during the second quarter from $1.6 million of expense during the first quarter.

This decrease in unit-based compensation expense was primarily due to annual awards issued under our LTIP during the first quarter as well as a reduction of our LTIP liability and recording of a corresponding compensation benefit due to our unit price falling $3.91 between the end of the first quarter and the end of the second quarter.

Cash settlements paid on our commodity derivatives during the second quarter were $2 million compared to $2.1 million paid during the first quarter. Unlike natural gas hedges that settled during the same month in which the corresponding volumes are hedged, crude oil hedges settle during the month after corresponding volumes are hedged.

After WTI crude oil prices averaged approximately $106 per barrel in March 2012, we paid settlements of $3.2 million on our March oil hedges in early April, which impacted our second quarter results. In contrast, after WTI crude oil prices averaged approximately $82 per barrel in June, we received settlements of $2 million on our June oil hedges in early July, which will impact our third quarter results.

This lag effect on crude oil hedges during a period of rapidly decreasing oil prices caused our cash paid on our oil hedges to be approximately $5.2 million higher during the second quarter. In contrast, this lag effect during a period of increasing prices caused our cash settlements paid on our oil hedges to be approximately $1.6 million lower during the first quarter.

We also reported unrealized gains of $86.4 million on our commodity derivatives portfolio during the second quarter, as the impact of decreasing NYMEX oil futures prices from the end of the first quarter until the end of the second quarter was partially offset by an increase in NYMEX natural gas futures prices over the same timeframe.

As a result of these unrealized gains, our commodity derivatives net liability of $29.5 million at March 31, 2012 was converted to a net asset of $56.9 million at June 30, 2012. In comparison, we reported unrealized losses of $21 million on our commodity derivatives portfolio during the first quarter due to increasing oil prices partially offset by declining natural gas prices.

Adjusted EBITDA decreased 26% to $40.7 million during the second quarter from $55.2 million during the first quarter, due primarily to lower realized commodity prices, due in part to increased oil differentials, a $5.2 million negative oil hedge lag effect in the second quarter and a $1.6 million positive oil hedge lag effect in the first quarter.

Development capital expenditures increased to $16.7 million in the second quarter from $12.2 million in the first quarter. In addition to our operated Wolfberry drilling in May and June, we also incurred capital expenditures on several successful workovers in Wyoming and the Permian Basin during the second quarter.

Our non-operated capital expenditures also increased from approximately $3 million in the first quarter to approximately $5 million in the second quarter. Both our operated and non-operated capital expenditures in the second quarter were heavily weighted toward the latter half of the quarter and, as such, will not have a material impact on production until the third quarter.

Distributable cash flow decreased to $19.1 million in the second quarter compared to $36.4 million in the first quarter. This decrease was due to significantly lower adjusted EBITDA, higher development capital expenditures, and slightly higher cash interest expense, which were partially offset by a $2.2 million decrease in cash settlements paid on LTIP unit awards.

We generated net income of $82.9 million, or $1.73 per unit in the second quarter, as unrealized gains of $86.4 million on our commodity derivatives were partially offset by lower realized commodity prices, due in part to increased oil differentials and a $14 million impairment charge on our oil and natural gas properties.

We reported net income of $7.4 million, or $0.15 per unit in the first quarter, which included unrealized losses of $21 million on our commodity derivatives and a $1.3 million impairment charge on our oil and natural gas properties.

We thank you for your continued support and confidence in Legacy’s employees. We encourage you to review our earnings release in full and read our risk factors and other more detailed disclosures in our Form 10-Q to be filed tomorrow.

At this time, we’d like to take questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from John Ragozzino from RBC Capital Markets.

John Ragozzino – RBC Capital Markets

Hey. Good morning, gentlemen.

Cary Brown

Hi, John. How are you?

John Ragozzino – RBC Capital Markets

Doing well. Thanks. Jim, with another $33 million expect in your budget this year, if you plan to say within that previously around $62 million budget. Can you give us a bit more detail on how that’s going to breakdown in terms of timing over tuning of 3 and 4Q?

Paul Horne

Let me take that. John, this is Paul Horne. We have not gone back to our Board and recommended in changing our capital budget. We are looking at that right now. Obviously, our views on that differ as commodity prices have increased compared to what it look like a couple of months ago.

So, I’m not ready to announce or even speculate on a change of that $62 million capital budget at this time. We are absolutely going to strive to smooth the reminder of our capital budget, assuming that it remains at $62 million and those increase to equal amounts over Q3 and Q4. You can’t always do that, especially when about a third of our capital budget is non-op capital but that should what we will look to do.

John Ragozzino – RBC Capital Markets

Okay. That’s helpful. Do you have a good feel for – throughout the second half of the year it actually looks like in terms of those non-operating fees?

Paul Horne

We have a good idea on the once we’ve seen. The issue with non-op capital, John, is quite often you are not aware of it and don’t know it until you receive the AFEs and typically or historically, what we’ve seen is a significant increase in AFE activity over Q3 as companies try to spend the remainder of their capital budget and trying to get that spend in Q4.

Historically, what you see with capital budget is Q1 is always low as you saw with legacy in our first quarter. Historically that just always happens because companies typically are trying to get the reminder of their capital budgets spend in Q4 and it takes a while to get backup and get projects going for the big year and we just saw that both and operated as well as non-operated CapEx in Q1.

Jim Lawrence

So, John, one thing you won’t see is rates return on our capital projects are really good and when you have a non-operated issue, it comes in and you get 30-days to respond and we probably will not let a short-term quarter coverage decision or even a coverage decision keep us from doing what’s in the best interest long-term. So we think about those – the reasons we delayed the rig dam in March and April is to make room for those kinds of things. But everything we are looking at – just has really good economics.

So, I’d rather have tighter coverage and do all the good projects that make a decision to not do the projects, so we can have a different coverage and so we are signed to stay at about $62 million but the opportunity set dictates and we are going to make the long-term decision, not short-term decision. So if it ends up at $65 million or $67 million, I’d have to come back to you guys and say, here’s why we are $65 million or $67 million. But we probably will not cut CapEx with the kind of rates return that we are seeing in all this stuff.

John Ragozzino – RBC Capital Markets

Okay. Great. We’ll stay tuned. Moving to the shale play, last quarter, you guys mentioned that there maybe some more results to discuss, come the third quarter. It seems like you interest in that area has been ramping pretty significantly with [demonstration and invention announcement]. Has there been anything noteworthy as far as your results or can you just give us update on where we stand there?

Cary Brown

To give you an update, we took a small interest, a 5% interest in FireWheel over there. We’ve closed on about 109,000 acres and probably end up at about 140,000 acres. We are in and around and directly offsetting Devon’s acreage there. Devon has drilled one well. Based on the results of that well, what I saw yesterday look like they’ve done a joint venture at about $7,200 an acre on that acreage with Japanese company I believe.

So the activity looks really good. We’ve drilled the first well, we’ve tested. We’ll get logs, everything look good, won’t know anything. Probably wait till late third quarter, early fourth quarter on the results more by frac.

Our first well in early August, in the next few days we’ll frac that. It takes a while and we took big fracs on these things. So, everything I’m hearing is really encouraging. Laredo, just get some wells out there, just get some wells out there and then of course Devon announced they are going to spend $1 billion after.

So, all of that is really good for us. Wish we had taken a bigger percentage than 5%, but we do have some acreage that’s not in those numbers that’s our old PDP production, that we own 100%. And that actually might be more valuable. We probably got 600 acres or so there. But it’s kind of fun to see that project come together and doing what we hope it would do, which is we estimate early exposure and we are learning some things and really feel good about depths.

It also has some – early results out, we told you guys we had some acreage in Ector County, Wolfbone area and hearing some really good things over there. That’s more of an independent play then public company play from what I’m seeing. But there is a horizontal well over there that looks stellar. So the good news is it’s – the places where we took little bit acreage look like they’ve been announced.

John Ragozzino – RBC Capital Markets

Great. Thanks a lot. And just little bit housekeeping. Jim, can you – I may have missed this and I apologize. But current liquidity position as of today or most recently?

Jim Lawrence

Right now, we have current availability for $133 million. We are about to get our volume base be determined by our bank group. And so we expect that to expand. We haven’t heard any feedback. We haven’t talked all of our banks yet, but three or four that we have talked to.

Gas prices will be down probably a tiny from the last borrowing base of gas prices that have already come down quite a bit. And there has been no indication so far that they are moving oil prices on us. And they have plenty of cushions built in there before last borrowing base, oil prices started off its 73 went up to 75 and stayed flat.

So there is still plenty of cusion between that and the stroke. So I think we are going to be in good shape.

John Ragozzino – RBC Capital Markets

Okay. Thanks a lot, gentlemen.

Jim Lawrence

Thank you.

Operator

The next question comes from Ethan Bellamy from Baird.

Cary Brown

Ethan, how are you?

Ethan Bellamy – Baird

Pleasing. Couple question for you guys. So what you’ve been expected investments in non-op drilling projects for those (inaudible) feets are big horizontal wells anything particularly sexy or attractive or perspective?

Cary Brown

The largest non-op project, we had about $2.5 million increase in non-op activity Q1 to Q2 and the most significant of that was additional learn energy horizontal well up in Panhandle. And it was drilled, completed and was not on line and producing during Q3.

It has started -- I mean, Q2, excuse me have has started producing and results are so early I am little bit tentative to say a lot, don’t look stellar, but sure going to make oil and gas is what you are seeing early, Ethan, that could change in -- it could end up a really goodwill. But nothing along at this point and not jumping up and down either on that particular well.

Ethan Bellamy – Baird

Okay. I recall that the first time, you had 10% provisions in some of those oil wells. They turned out not to be of that grade. Do you have any more of those in the pipeline?

Cary Brown

This was a final location that we have acreage that we bought from Cline Shale wells.

Ethan Bellamy – Baird

Okay.

Cary Brown

You’re right. Your memory is perfect, 10% interest on roughly $9.5 million drilling complete well, so it’s about a $1 million net of what you see.

Ethan Bellamy – Baird

Well, right, you recall my memory is far from perfect. It is my way for to show you. With respect to, you guys probably saw clearly folks in own results but we saw Vanguard announce their shift to monthly distribution from quarterly today. Have you guys looked at that, does that make any sense to you?

Cary Brown

Haven’t looked at it. We have not looked at that and I can honestly say and all the visits, all the calls that we’ve had from investors and visits to offset in the retail side. We have never heard strong as that.

Ethan Bellamy – Baird

Fair enough. How many Wolfberry wells did you drill in May and June, and did those coming on the tank curve and what is your current tank curve?

Cary Brown

Great question, Ethan. We drilled four wells in May and June, operated Wolfberry wells. None of those wells start producing oil and gas in Q2. The first well that we drilled was flat and water was flowing back. Flowing back water in the quarter, the second well was flat but not -- plugs we’re not drilled down and so it was not even on production.

We have subsequently fracked the third one of those wells here in the last few days. So, I can’t respond it all to how those wells are doing compared cap curve because it’s just too early. Haven’t seen anything alarming in the first well that we completed and brought on line. It is starting to have a good oil curve.

Our tank curve were pretty significantly from area-to-area in the Wolfberry. We really don’t look at Wolfberry as a general type hurdle across the region and a very specific not only within counties but even least to least. But generally speaking, the answer to your question, all tank curves would range from a low of 100 Mboes to 150 Mboes. And generally, we are in the 120 range on our tank curve investment.

But I can tell you is we have been tracking all of our Wolfberry wells historically since we pick the rig up and started drilling and the averages on both the 80 acre floods and the 40 acre floods have exceeded our tank curves.

Ethan Bellamy – Baird

Okay. In IP rate?

Jim Lawrence

Again, dramatically different depending area-to-area, but typically here in 150 to 200 range on our IP. We don’t believe that in the Wolfberry IPs are necessarily a good prediction of EURs. We’ve seen well that only come in the 125 barrels a day that don’t have this higher decline and holding that much better. We had well, if you remember last year about this time the IP doing 750 to 800 range in Boe and its last when you get one of those.

Ethan Bellamy – Baird

I imagine so. Thank you. Appreciate it.

Jim Lawrence

Absolute those numbers were Boe per day not barrels oil per day, but Boes per day.

Ethan Bellamy – Baird

Okay. Thank you.

Operator

The next question comes from Kevin Smith from Raymond James.

Cary Brown

Hi, Kevin. How are you?

Kevin Smith – Raymond James

Doing all right. Good morning. Depending overall, I assume that was a horizontal granite wash all right, not a [hard shooter]?

Cary Brown

Yes, sir. I am sorry.

Kevin Smith – Raymond James

Okay. Thanks. And then there is discussion, I know for while of drilling an operated Yeso well in the fourth quarter. These June results you are seeing in the Wolfcamp or even potentially in the Cline Shale, if you want to move that, that well around or how are you thinking about that?

Jim Lawrence

Kevin, that's a great question. We’ve been talking about that very subject to in the last couple of weeks. I actually at this point don't think we would drill the Yeso well in Q4, not so much because that we don't think the results there will be stellar. We are just seeing some really good opportunities, actually more specifically in the Horizontal Bone Springs.

We are going to be spread the well here in a couple of weeks and operated well in the Horizontal Bone Springs in Lea County. We have seen a couple of really exciting non-operated projects of Horizontal Bone Springs at least that we perceived in the last month or so. And so I think probably what we are going to do, it looks like at this point, it is shift that Yeso CapEx to some Horizontal Bone Springs CapEx in New Mexico.

It's not necessarily because that's significantly better economics, it's because -- as Cary mentioned earlier, especially on those non-op AFVs, you have got a choice to either do it alone or do a non-consent, and lose those reserves forever. We control the acreage of the Yesos, it's HBP.

So we are not in a position that we have to drill those on any time line and we sure don't want to miss out on some really good opportunities that our partners are seeing the Horizontal Bone Springs.

Kevin Smith – Raymond James

Got you. So the way we should interpret kind of a newer well, exploratory, I guess somewhat more is just based off trying to hold acreage versus rate of returns?

Jim Lawrence

No, it's not holding acreage, it is HBP, the non-op. Well, I think you are asking me, it's HBP. But it's just a non-op well that the partner is going to drill. So our choice is to approve the AFV and spend about $1.2 billion net to Legacy of capital on that project, or go non-consent and lose those reserves, because we are 400% totally recall us on a JOA, and lost those reserves forever. So it's actually not a HBP acreage, it's just a JOA issue on a non-operated production.

Kevin Smith – Raymond James

Okay. The Horizontal Bone Springs will be an operated well, right?

Jim Lawrence

Actually there's several. We are going to drill one on our Lea unit in Lea County. In fact, that well should be spudded in the month of August, and the well that I have been talking about that has caused us to move the Yeso CapEx is a non-op well, is also in Western Lea County, but in an excellent area with outstanding results surrounding it. So we are really excited about that horizontal -- no it's a Horizontal Bone Springs, it's not -- Wolfcamp is Horizontal Bone Spring.

Cary Brown

Now, we get a lot of questions on capital, and want to kind of make a point to you guys. I know I have told you guys this before. We don't try to make the determination what's maintenance cap, what's growth capital, and we know internally, this summer what we are spending is growth capital.

We are not comfortable being able to tell you how much is growth and how much is maintenance, because it's just really hard to figure it out. So just when you look at coverage for legacy, always take into account that we are using all of that capital and we -- I don't think all of that capital is for maintenance. I think all of that capital is included, because that's the only way we know how to do it and be straightforward about.

Jim Lawrence

That was the point Cary that I wanted to make. You speak of production decline, and I believe we have kind of told you guys on this call last quarter that you should probably anticipate that. And the reason for that is, we spent a little over $40 million capital in the second half of '11. We intentionally did that. Prices were good.

We had great projects and felt like that was an opportunity to grow our production and when you go from $40 million and $22 million in the second half of '11 and cut back to a little less than $30 million in the first half, you are going to see a decline off of that.

Compound that with a very low first quarter and second quarter production, I am actually really pleased with where the second quarter production came in. It was higher than we had anticipated it to be, and a big part of that was due to some excellent work that was done by our employees in the Rockies. We had some very good workover, capital workover that was spent in the Rockies, and then we had some very good workover capital spend in the Permian as well.

So when you see those kinds of swings in capital, you can anticipate that, and we did that intentionally, that was planned, because the second half of last year, prices were so strong. And we had the opportunity to spend certain growth capital. And we sure sold those volumes in Q4 and in Q1.

Kevin Smith – Raymond James

Fair enough. That's good color. Just one more question for me and I will hop off. If you could comment on the line pressure you are seeing at the gas plants and also comment on -- if you are seeing sort of ethane rejection. How we should be thinking about your volumes with ethane prices being so up?

Jim Lawrence

I will comment on the pressure issue. What we are seeing and it's the most significant in a Wolfberry area is, with all of this development work that's being done, line pressures have been increasing, the gas companies are working on that, installing compression where they can.

We are talking with them daily and looking at opportunities to put in our own compression, some of this gas goes into low pressure systems. And so you can't pressure it up and cause that line problems. But it's not just in the Wolfberry that we are seeing, that's where it's worse, but we have seen it in a number of areas -- and it's not surprising with activity that's going on.

I don't think it's something that it is going to be a huge issue long term, based on the conversations we are having with the pipeline companies, but also don't think it's up and it's going to go away tomorrow either.

Cary Brown

On the NGL front, Kevin, our NGLs are kind of in two pieces. We have our production that's up in the Texas panhandle in our Binger unit that produces the vast majority of the NGLs that we report, because we split those out up there. But we book our NGLs in the Permian basin as part of our wet gas stream.

So you see that in our premium to -- the premium of our gas prices of our Henry Hub, up in the panhandle, there is only roughly, in terms of volumes, roughly 12% is in ethane, and another 28%, 29% is in propane. And on a value basis, that used to be a little bit closer to 20% that is now 15% right now, because in June ethane was basically spurt (inaudible).

So you are seeing 85% of the value there that is in heavies. The percentage of those heavies to WTI is starting to slip a little bit, but it's still nothing like what you see on the ethane side, especially, and also in propane. That's why I think you are seeing our NGL prices hold up fairly well and we have been able to -- and historically we have hedged those on a two to one basis, carrying two NGL barrels for one crude barrel.

We have hedged those with crude, considering that, that's a much better market to do hedging on the -- the NGL hedging market is not very liquid when you went out 12 to 18 months, and it's kind of hard to get things done.

On the Permian side, roughly 40% of our volumes are in ethane on the NGL front. Another 30% are in propane. As far as value goes, that's roughly 40% to 45% or so. So you are seeing an impact there on the premium of our Henry Hub -- I mean, natural gas prices fell by $0.50 on the dry gas side from quarter-to-quarter roughly $0.05 and you saw a bigger reduction in that in our gas prices, because our premium upper Henry Hub sales were roughly, it was between $1 to $1.95 last year. It went up to about -- when oil prices got really high, went up to about $2.10, this quarter it fell down to $1.62.

So even when you take all that in, if you say okay, because of the decline in propane and ethane prices and getting a little bit lower percentage of WTI on heavies, even if that cost a 25% on our gas price, that's $600,000. That's just not -- it's not going to be a huge driver for us either way.

Kevin Smith – Raymond James

All right. Great. Thanks for the input.

Jim Lawrence

Thanks Kevin.

Operator

The next question comes from Praneeth Satish from Wells Fargo.

Praneeth Satish – Wells Fargo

Hey guys, good morning.

Jim Lawrence

Hi Praneeth, how are you?

Praneeth Satish – Wells Fargo

Good, good. Just two quick questions. With all the moving pieces this quarter, just wondering if you can provide an indication of what production is currently running at or where you exited at the end of the quarter?

Jim Lawrence

I would expect production in the third and fourth quarter to be up over the second quarter. Not dramatically.

Cary Brown

I would say that when we've talked to people somewhere in the range of where we were in Q1 probably at the low to a high of a couple of percentage points higher than that. At least for Q3.

Praneeth Satish – Wells Fargo

Okay. And the other question is just given the company's increased size, have you looked at potentially terming out some of the borrowing from the credit facility, with high yield debt?

Jim Lawrence

We have been looking at that very, very closely.

Cary Brown

Talk about most of that.

Jim Lawrence

And I think you will see us do something on the high yield side. I am not saying it's going to be some time this year, but its' going to be some time in the next six to 18 months. I think you will definitely see us go that route, to getting the game on large acquisitions, that's a very important piece of the puzzle.

Praneeth Satish – Wells Fargo

Okay. Great. Thank you.

Jim Lawrence

Thank you.

Operator

The next question comes from Bernie Colson from Global Hunter.

Jim Lawrence

Hi Bernie, how are you?

Bernie Colson – Global Hunter

Good, good. How are you doing?

Jim Lawrence

Good.

Bernie Colson – Global Hunter

Actually the question that I had were on line pressure stuff. I am good. Thank you.

Jim Lawrence

Thanks Bernie.

Operator

The next question comes from Chris Sighinolfi from UBS.

Jim Lawrence

Hi Chris. How are you?

Chris Sighinolfi – UBS

Hey guys. I am well. Most of my questions were hit as well, but sort of one conceptual question I would like to discuss. The basis blowout that was experienced this quarter, we have chatted in the past around what Permian Basin supply looks like relative to takeaway capacity? Is there an appetite at all, as you think about your internal view of what might happen to basis to try and seek to hedge that exposure directly?

Cary Brown

The market to be able to hedge WTI to Cushing -- middle of the Cushing is very new, and it's a very choppy, illiquid market. There are only a couple of other banks in our credit facility that actually do that. And one of them prices much better (inaudible).

But, it's pretty tough to get those deals done. So we have certainly looked at that. If we would have reacted during the second quarter, when banks were flying sky high, we could have locked in for 3.50 for a long period of time, and ultimately that would have been a mistake.

So when we are seeing differentials at 4.90 that we averaged for the second quarter, for the first couple of days this month already, we go back inside a $1. We should average about $1.50 for the third quarter. I think we are comfortable with where they are right now.

And also when you look at all the various projects that are coming on in terms of expansions, the various pipelines that are existing right now, and then Longhorn coming on in the first quarter of next year, I think we feel there are going to be hiccups that happened when you're in an area where capacity is tight and production is high, activities high.

When things go offline, you are going to see a few bumps in the road, but overall with all the expansion projects at Longhorn, we feel good about things on a long-term basis and don't want to lock in something that's too high.

Operator

(Operator Instructions) The next question comes from Michael Peterson from MLV & Co.

Jim Lawrence

Michael, how are you?

Michael Peterson - MLV & Co.

Good morning, gentlemen. Doing well. Thank you. A couple of detailed questions if you would this morning. First one if you can give us a little bit of color on the $14 million impairment? And the second question, if you can provide some production or reserve data, you gave some good disclosure around the North Dakota and Montana acquisition, but there are I believe six additional that closed during the period. It will be helpful if you can provide any insight into part of those two topics.

Jim Lawrence

Yes. On our acquisition – and you will see a typical kind of breakdown that we show on our presentations, we are going to be attending the MLP Conference that Citi puts on the later part of this month, and the full detail will be there at that point.

In terms of where the acquisitions are shaking out on a total basis, we made a $107.6 million of acquisitions on a year-to-date basis through June 30. Those remained at roughly 4.2 – excuse me at 5 times cash flow, flat.

Michael Peterson - MLV & Co.

Okay.

Jim Lawrence

Roughly 90 – 80% on the PDP side, 85% oil and NGLs, the vast majority of that being oil obviously with the acquisition that we had up in North Dakota and Montana.

And in terms of the impairment charge, it was – obviously when prices drop, you are going to see some impairment charges that happened. The bulk of the – a little bit more than half of that – as you will see this in our 10-Q that gets filed tomorrow, a little bit more than half of that is an impairment on these North Dakota, Montana acquisitions that just happened. And it is an anomaly of the accounting rules. Sometimes as we were talking yesterday on our committee call, sometimes the accounting rules come back sense the people in the business world, but we saw – follow them.

We are not able to count the value of our hedges against that acquisition. So when we closed this and we hedged that we hedged at the time at which time the PSA at $106 for the next 12 months going down from $100 to roughly $96, $97 and in some good, if you recall us in years ’04 and ‘05.

We weren't able to count which have a mark-to-market value. Of course, we had some incremental values in there too, but we had a mark-to-market value of roughly $12.2 million at June 30th.

We weren't able to count those in our impairment calculation, so we had to take $7.8 million impairment on that because we signed the PSA we catch. We were in good shape, but that was the exact same time where commodity prices declined significantly.

Michael Peterson - MLV & Co.

Okay, understood. So the lion's share of the impairment was driven by price not a reevaluation of resource potential than flat price?

Jim Lawrence

All driven by price.

Michael Peterson - MLV & Co.

Perfect, thank you very much.

Jim Lawrence

Thanks.

Operator

I am now showing no further questions. I would now like to turn the call back over to the speakers for any closing remarks.

Cary Brown

Great. Guys, I just want to say thanks for, especially the analysts who covers and thank you for the time to dig into these numbers. And we feel real good about where we are and what's coming up for the second half of the year, try to give you guys good color on that but feel great about our distribution and good pipeline of acquisitions to look in.

Time will tell what commodity prices did. We are hedged against commodity prices, but we do have some exposure, both good and bad. The more of three white collars we use the more exposure we have to the upside.

And in these windows where you are playing in that inside of that collar, it looks like there is more volatility than there really is. But as management team, we feel great about where we are and where we are headed. And I want to say thanks to all our unitholders and analysts for taking the time listening us today.

Jim Lawrence

As always, if you have any further questions, please don't hesitate to call. Thank you all for calling in today.

Cary Brown

Thank you, [Suzanne] and all. Thanks, guys.

Jim Lawrence

Thank you.

Operator

Ladies and gentlemen, that does conclude the conference for today. Again thank you for your participation. You may all disconnect. 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 Q2 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts