Legacy Reserves LP. Q2 2009 Earnings Call Transcript

| About: Legacy Reserves (LGCY)

Legacy Reserves LP. (NASDAQ:LGCY)

Q2 2009 Earnings Call

August 6, 2009 3:00 pm ET

Executives

Cary Brown – Chairman and Chief Executive Officer

Steve Pruett – President and Chief Financial Officer

Paul Horne – Executive Vice President Operations

Analysts

Michael Hall – Stifel Nicolaus & Co.

John Freeman – Raymond James

Leo Mariani – RBC Capital Markets

Ethan Bellamy – Wunderlich Securities

Yves Siegel – Credit Suisse

Richard Dearnley – Longport Partners

Operator

Welcome to the Legacy Reserves second quarter 2009 earnings conference call. (Operator Instructions). I will now like turn the conference over to Mr. Pruett.

Steve Pruett

Before we begin we'd like to remind you that during the course of this call we 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 today and you should refer to the additional information contained in Legacy Reserves LP's Form 10-K for the year ended December 31, 2008 and our earnings release filed yesterday afternoon, along with our 10-Q which will be filed tomorrow and subsequent reports and press releases as filed with the 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 and Mid-Continent regions.

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

Cary Brown

I'm pleased to report we've had an excellent second quarter. EBITDA increased to $32 million and distributable cash flow increased to $0.79 per unit, which allowed us to comfortably pay our $0.52 distribution with over one and half times coverage.

The overall environment feels much improved. Capital markets are open again. The banks appear to be in better moods. Oil prices have continued to improve. Our hedge portfolio has proven to be effective, allowing us to maintain distributions despite the dramatic decline in commodity prices.

There are some signs we may even be seeing the acquisition market open again. We're continuing to look at acquisitions, and I'm encouraged that we may be getting back to a situation where buyers and sellers can agree on price.

We did have a slight decrease in production as expected because of the high levels of CapEx in the second quarter and second half of 2008. As that drilling declines and continue declined, we'll see a slight reduction in production, about 2%. If we don't significantly increase CapEx I expect to see slight volume decreases through the end of 2009.

Once again I'm extremely pleased with the quarter. I'm excited to be back on track with cash flow and acquisitions. The distraction of the Apollo transaction is behind us, and I'm confident that the decision to stay on the current path will prove to be the best answer for our unitholders.

With that I'll turn it over to Steve to give more details into the numbers.

Steve Pruett

We are pleased to report unaudited preliminary financial information extracted from our Form 10-Q which will be filed tomorrow morning. I will make comparisons to the results of the second quarter of 2009 to that of the first quarter of 2009. This information is contained in our earnings release and for a more detailed disclosure we encourage you to access our Form 10-Q which will be available in the EDGAR system and our Website tomorrow, Friday, August 6.

I'm going to jump right into the numbers, hopefully shed a little more light on our quarter. As Cary mentioned, our production rate was 8,154 Boes per day. That was off from the first quarter about 2%. That's primarily rooted in our elevated capital investment program the second half of 2008 which was $25 million.

We had a 75% decline in our CapEx in the first half of this year, down to $7.4 million and all of the drilling and completion activity, particularly in the Wolfberry trend and the Fuhrman-Mascho created a decline rate that has now stabilized, and we expect our production outlook to be more stable going forward. But there is an impact of reduced capital spending first half of this year compared to the elevated level in the second half of last year.

Our revenues were about $32 million from the sale of oil and natural gas liquid and natural gas, compared to $23 million in the first quarter of 2009, a 38% increase. If you include the realized swap proceeds, or settled swaps, we had revenues of $48.6 million, compared to $42.1 million in the first quarter of 2009. So you can see that our swaps enhanced our revenues.

Realized prices for oil, without the benefit of any swaps, were $55.79 that's up 56% from the first quarter when we realized about $35.79 per barrel. Natural gas was relatively flat quarter-over-quarter, $3.79 this quarter compared to $3.62 in the first quarter.

Including the effect of our swaps and our swap settlements we realized $84.55 per barrel for oil in the second quarter. That is up 24% from $68.21 per barrel in the first quarter of 2009. Likewise on our natural gas realization, including the benefit of swaps, $6.79 almost doubling of the impact or the wellhead price including the benefit of the swaps, that was up 4.5% from $6.50 per Mcf in the first quarter.

Swap settlements were $16.7 million in the second quarter. That's down from $19 million in the first quarter as you'd expect since prices increased our swap settlements were somewhat lower. We did realize about a $3 million benefit in the second quarter due to the swap, what we call the swap lag effect, which as prices are rising, collecting our oil swaps in the subsequent month benefit us when prices are declining as they were in the first quarter. It can be a detriment, and we had a detriment in the first quarter of about $1.3 million due to the swap receipt lag effect.

Production costs were relatively flat quarter-over-quarter. Production costs for Boe this quarter were $14.38, excluding production taxes. That's up slightly from $14.07 in the first quarter. We feel like our production costs have bottomed out but we think they're still relatively stable. And even with improved oil prices, because gas prices are so weak we don't see a lot of upper pressure on our production costs.

Our production taxes for Boe, this is both severance and ad valorem tax, went down slightly in the quarter at $3.61 per Boe, compared to $3.76 in the first quarter and that's a decrease that's primarily due to adjusting our ad valorem tax to grow slightly quarter-over-quarter.

DD&A for Boe decreased over the period as did DD&A itself, $13.5 million for the quarter, $16.6 million in the first quarter. And the DD&A for Boe was $18.26 in the second quarter down from $22 and change in the first quarter.

General administrative expense was $3.9 million in Q2. That included $1.1 million of costs related to our Apollo take-private process, primarily legal fees along with the financial advisory fees. That's up slightly from $3.4 million in the first quarter which also included about $200,000 of those Apollo-related professional service fees.

We do believe that subtracting that elevated one-time expense from our run rate is more reflective of our run rate of around $2.8 million to $3 million a quarter for G&A, which should pull our G&A back below $5 per Boe.

Cary mentioned our adjusted EBITDA of $32 million, a very strong quarter. That compared to $24.7 million in the first quarter so price increases along with flat costs more than offset a slight production decline.

Our development capital was needed in the second quarter of $2.6 million, down from $4.8 million in Q1. Distributable cash flow accordingly was higher, $24.7 million compared to $14.9 million in the first quarter. And those distributable cash flow per unit figures therefore will be $0.79, compared to $0.48, so over one and half times coverage.

Accounting for the swap lag effect our distributable cash flow per unit will be $0.70 per unit or about 1.34 times coverage, compared to about one times coverage in the first quarter when we had a detriment due to the swap lag effect.

Impairment was half a million dollars this quarter, compared to $1.1 million in the first quarter. Net income or net loss reported was $57 million this quarter. That's a consequence of the unrealized loss on our commodity swaps of $75.8 million in the quarter which was actually relatively flat in the first quarter.

We did realize a LIBOR swap gain of $6.8 million. That is the reason we had a reported net interest income for the period of about $1.7 million. If you back that out, you would see that we have, on the last page of our earnings release, you'll note that our cash interest expense was about $4.66 million, which is more appropriate for looking at your cash flow models for Legacy's coverage.

Backing all of that is the unrealized gains and losses on our commodity and interest rate swaps would give us a normalized, or an adjusted net income of $12 million. And that would compare to about $4.4 million of adjusted net income backing up those unrealized gains and losses on our swaps of $4.4 million, or about $0.39 per unit for the quarter two compared to $0.14 in quarter one.

I'll now move to comparing the first half of 2009 to the first half of 2008. It's a little different period. I'm doing that to contrast the effects of high commodity prices experienced in the first half of last year compared to the reduced prices and costs in the first half of 2009.

Production was up 16% largely due to our acquisition and development activities, 8,238 Boes per day compared to 7,088. Realized prices without the benefit of swaps, oil was $45.58 in the first half of this year, less than half of $109 average in the first half of 2008. Natural gas likewise down dramatically to $3.71 per Mcf compared to $9.85 in the first half of 2008.

Including the swaps you can now see the benefit of, or the hedges mitigating the volatility, $76.21 per barrel compared to $84.28 per barrel in the first six months of 2008. And that's driven by swap settlements of $35.6 million this year compared to $21.3 million of swap payments for the first half of last year.

Production costs were $14.22 per barrel compared to $16.48 in the first half of last year. You may recall our production costs peaked at about $20 per barrel in about the third quarter of last year, and we're happy to report those are down significantly and seem to be stable.

G&A per Boe in the first half of the year $4.87 per barrel and that includes the effect of the one-time expenses related to the Apollo take-private transaction. Adjusted EBITDA for the first half of the year $56.8 million, a very slight decline from the first half of last year at $58.6 million, thus we had about 1.22 times coverage in the first half of this year compared to about 1.47 times coverage first half of last year.

One other note, the development capital was flat in the first half of this year compared to first half of last year at $7.4 million. The elevation of our capital spending happened in the second half of 2008. We had a relatively stable first half.

The net income effect, or reversing out the impact of unrealized gains and losses on our commodity swaps and our LIBOR interest rate swaps, would give us adjusted net income in the first half of $16.4 million or $0.53 per unit, and that compares to $37 million or $1.19 per unit in the equivalent period last year.

Terry already addressed our take-private offer situation, but as you recall on April 3, 2009 our Board of Directors announced the receipt of a proposal from Apollo to take Legacy private at a cash purchase price of $14.00 per unit subject to any downward adjustments for distributions paid to the partnership's limited partners.

On June 24 after careful review of the proposal letter and subsequent negotiations related to the Apollo proposal letter, Legacy's Conflicts Committee, which was comprised of independent directors, determined that it was in the best interest of the unitholders of Legacy to terminate discussions with Apollo management.

We thank you for your continued support and confidence in Legacy and its employees. We encourage you to review our earnings release in full, to read our 10-Q to be filed tomorrow, along with reviewing risk factors and other more detailed disclosures in our annual report

At this time we would like to take questions.

Question-and-Answer Session

Operator

(Operator Instructions). Our first question comes from Michael Hall – Stifel Nicolaus.

Michael Hall – Stifel Nicolaus & Co.

Just some questions on your current approach to the market, I mean, there's some big packages that have changed hands in the Permian, and the Permian-like areas in a somewhat recent term and then there's a pretty large package out there at this point. And then in the past you've always kind of been more of like you say, kind of singles and doubles and not necessarily looking at the real large packages. Is there any change in appetite on that, as we are in kind of a trough-type setting for the industry, and maybe see anything out there that peaks your interest in taking a bite at something pretty large?

Cary Brown

Well, Michael, we look at all those packages and I would say we've never wanted to work harder than other guys and only do small deals, but at our core we're value guy and sometimes on those big marketed packages you'll see more reserves than we see or we see a risk. We'll risk weight some of those reserves maybe differently than other guys will.

We've never not wanted to do the big deals and we've always looked at them. It kind of feels like an environment where you might do some bigger ones because of, where particularly the [GATNE] guys are still going to be in somewhat of liquidity price, we're not concerned about borrowing base redetermination of fault boring because we're primarily oil. If we were primarily gas I think we'd have a different take on what that situation is going to look like. So it may be a situation where we can knock one down.

Michael Hall – Stifel Nicolaus & Co.

Okay, appreciate the color there. And then just if I may one more, looking at the cost outlook, you made the comment in there Steve, sounds like maybe the costs you think are bottoming here. How long do you think we can kind of keep these low levels of costs in terms of duration, a couple of quarters? Or do you think we'll make it all the way into maybe 2010 or so?

Steve Pruett

Since I made a commitment for Paul Horne who's responsible for production costs – I assume you're talking production costs – I'll turn this over. He's the real star. Paul's our EVP of Operations.

Paul Horne

Michael, I'm smiling. Tell me what your price forecast is and I'll tell you what the expenses will be.

Michael Hall – Stifel Nicolaus & Co.

All right, how about we hover around 72?

Paul Horne

I think our current expense levels in this price range have settled. I don't expect any significant changes unless we see some significant changes in product prices. And for us I think a significant change in gas price will probably have a larger impact than oil price. Because we are oily, far and away our largest lifting cost area is electricity and electricity generally tracks, although we use a lot of coal flat fires in electricity, it generally tracks with natural gas prices.

Michael Hall – Stifel Nicolaus & Co.

Okay.

Steve Pruett

Michael, if you think about the rig count, when it was 2,000 it was so driven by gas rigs running and there's not nearly as many gas rigs running. The Permian Basin rig count was at 350 at the peak, it bottomed at about 80 and it's back to about 110. There's still a lot of excess iron, not only rigs, but well service units that not only work on our wells but also are used to complete gas wells. Well a lot of those are stacked up in the yards.

In particular, Paul's comment on the lower cost of frac and stimulate wells that are a fraction of the cost. I think I heard Paul say an 80% plus discount on fracture jobs on our Wolf Camp well for example. So there's a lot of horsepower in the yards for pumping frac jobs or cement and that's very helpful.

So just the decline in gas rig count has been a real benefit to lowering cost on well work and capital projects and even maintaining our wells, and until we see Paul notes gas prices recover to a point where the rigs start running back out to drill a whole bunch of gas wells, we think costs will be pretty stable both on the capital and operating side.

Michael Hall – Stifel Nicolaus & Co.

Okay. And so will those changes in activity levels you think will have more of an impact or less of an impact than changes in commodity price levels? Obviously they're related but as it relates to an in field cost versus an activity related cost, follow?

Paul Horne

Yes. I think they're both absolutely related.

Michael Hall – Stifel Nicolaus & Co.

Clearly.

Paul Horne

Right now the gas price is suppressing the goods and services market just because there isn't all that iron running. I think where there may be some cost recovery and probably needs to be for our service company partners, is on the side of the capital costs.

Things are very depressed right now and that's great for us. We can do our capital projects at very good attractive prices. But they're probably a little bit over depressed and I expect those to recover, but that's not lifting cost expense associated costs. It's more of the fracture stimulation, the drill and rig rates and those kinds of things. So I agree with Steve, I think you'll see some recovery of capital costs. Don't expect as long as we stay in this current price environment to see any significant change in operating costs.

Operator

Our next question comes from John Freeman – Raymond James.

John Freeman – Raymond James

I'm trying to get a sense of kind of what level of CapEx you think you would need to spend to kind of maintain production levels given the kind of current asset base you've got.

Cary Brown

Thanks John, we always like that question. We never answer it, but we always like to have it. And there's just so many variables in it, John, you can't – it would be inappropriate for us to even try to answer that question.

John Freeman – Raymond James

All right, it was worth trying. I'm trying to get a little bit of a sense – we've talked about the service cost side of it. I'm wondering in addition to just kind of rig rates and frac costs and things like that, where do you all stand on kind of your tubular pipe kind of inventory? Are you worked it off? Are you benefiting from being able to buy that that you maybe bought last year?

Paul Horne

Yes. We have a very small inventory of pipe remaining that we paid higher cost for. It's specifically some larger pipe diameters that we'll use when we drill wells that we need that pipe. Other than that, we worked our inventory off and are able to take advantage of current low costs.

John Freeman – Raymond James

So it's safe to say that your prior couple of quarters here, you have not benefited yet from that but you will going forward?

Paul Horne

We have benefited in our prior quarter from that, but we've benefited very insignificantly because we have had two quarters of significantly lower capital costs than our norm.

John Freeman – Raymond James

And then obviously I know we always kind of focus on the Permian assets but I'm sure you all have noticed that some guys in the industry have had some pretty phenomenal wells in the Granite Wash and obviously with your Texas Panhandle assets it looks like some of that at least is near some of these areas that have been drilled at maybe Stiles Ranch or Buffalo Wallow. Just any comments you all maybe have on if you've looked at it. Just any color you could add?

Cary Brown

We're not a big driller, John, and we're looking primarily for development drilling in and around the stuff we have. We have not looked at taking a big acreage position in those areas yet. Doesn't mean we won't but today we have not.

John Freeman – Raymond James

I was looking at more from the angle if you had any acres. It was perspective that maybe you could sell to some of these other guys.

Steve Pruett

John, truth be known, we're in the Panhandle West field and we do not overlap with the Stiles Ranch or Buffalo Wallow Granite Wash pipe. I wish we did but we're further west out of that trend in the traditional Brown Dolomite massive panhandle field that's highly depleted so we just don't have that, we actually are completed in the shallow Granite Wash in some of our wells but it's just a different beast entirely down part of the basin where the Granite Wash gets deeper and the activities have been going on.

John Freeman – Raymond James

Yes, I saw the Hutchinson County is what I thought may have had a chance but that's very helpful.

Operator

Our next question comes from Leo Mariani – RBC Capital Markets.

Leo Mariani – RBC Capital Markets

Just a question on acquisitions, you guys talked about looking at a lot of the major packages. You talked about the buyers and sellers prices kind of getting a little bit closer now. Are you guys kind of pretty hot and heavy in looking at deals and do you think there's a decent chance that something happens in the next couple months?

Cary Brown

I would say yes, Leo, we're starting to see – anytime you have prices go down so much and then they start coming back, the guys that think they might want to sell sometime are starting to circle around and say hey, this may be a good time.

So I'm encouraged that we may be getting to a time where we can meet seller expectations and actually still make sense for us. So I think we’re back on track with looking at that. You never know with acquisitions. We've done a few small little ones, a half million here, $3 million there, but nothing significant.

Steve Pruett

We like our deal flow though and we like the, as Cary mentioned earlier, the sense of distress among some players that are leveraged and with banks adjusting their gas price forecast downward, we're going to need to sell some non-core assets to either pay down debt or to fund their drilling programs in other basins, so we're a natural home for non-core Permian assets and like the deal flow ahead of us.

Cary Brown

If you look at a guy who's got a bunch of gas acreage selling a little bit of oil, PDP oil, into this strip and using that cash to develop his gas acreage, it's a pretty good play on their part and we're seeing some interesting things around that.

Leo Mariani – RBC Capital Markets

You guys talked about being pretty comfortable with your fault boring base redetermination. Have you have had specific conversations with the banks regarding that?

Steve Pruett

The conversations we have, Leo, is just taking the pulse on their price forecast and it's a little bit early for some of the banks but some, including some of our larger banks, have already determined their price forecast for the fall, particularly in oil, and it's definitely come off the bottom. The bottom was in the $50 to $55 per barrel range for their long-term oil price outlook which is, for Legacy, the most important determinant of our borrowing capacity because we have such a large hedge inventory in the near term in the next 4.5 years and now that's looking to be $60 to $65 per barrel, so that's a big impact on Legacy's borrowing capacity.

On the gas front, I think the banks are still scratching their heads and that's less impactful to Legacy since that's only about 12% of our revenue stream and we do have a good hedge position in natural gas. And to the extent that the banks ratchet their gas price forecast down as they should, the impact of our gas swaps is even greater in supporting our borrowing base.

So I think net-net the oil increase is going to much more than offset our decline in the bank's gas price forecast. The health of the banks is a lot greater, their confidence and willingness to lend. The calls we're getting, the return calls we're getting from the banks that may join our credit facility down the road when we need them is encouraging.

So to the health of our banks, their improved oil price forecast – in fact, we've done some incremental hedging. We've done some conversions of PUDs to PDP and we'll likely have some more PUDs to book down the road. I think all bodes well for the follow re-determination for Legacy.

Leo Mariani – RBC Capital Markets

And do you guys have thoughts on your CapEx spending for the second half of '09?

Steve Pruett

I'm glad you brought that up. I meant to mention that. One thing that management will be recommending to our directors at the next meeting will be an increase in our capital budget from the $10.7 million level.

Given what Paul said about cost compared to, and most of our projects opportunity are oily, the cost to exploit those projects is so low and we're selling oil for close to $70 a barrel right now. The economics have never been more compelling.

And so we are, Paul and his team have put together a great project inventory and we'll be taking some of those to our directors soon to elevate our capital budget modestly. So stay tuned for an announcement on that should the board adopt management's recommendation. That would be primarily in the fourth quarter but there's some work that we're turning on even in the third quarter.

Leo Mariani – RBC Capital Markets

I guess the last question from me here. I noticed that your gas price pre-hedge in the second quarter seemed pretty high, roughly in line with NYMEX. I was just curious kind of if you guys have any idea what was kind of going on with that?

Steve Pruett

Say that again Leo? I didn't follow about our gas hedges?

Leo Mariani – RBC Capital Markets

Yes, your gas price realization prior to hedging I think was 379 the second quarter.

Steve Pruett

What's going on there is while NGL prices are still depressed, there's enough NGL in our gas stream. We break out NGLs in the Texas Panhandle because the purchasers tell us what they recover in NGL and we book it as such.

But in the Permian, most of our NGLs are booked as wet gas sales. And there's enough value add because of where NGL prices are vis-à-vis the BTU equivalent of net gas that that NGL sale on a 1,200 BTU gas stream gets us a big lift on our realized wet gas prices.

So that's really what's happening is there's such a disconnect between oil and NGL prices vis-à-vis net gas that the NGL's giving us a big lift where we sell wet gas or get booked as wet gas. There's still some room for NGL prices to improve relative to oil prices.

Operator

Our next question comes from Ethan Bellamy – Wunderlich Securities.

Ethan Bellamy – Wunderlich Securities

You must have picked a really good time to hold this call this quarter.

Steve Pruett

We have a lot of people. We listen to you all, especially Michael. We had eight or so competitors with calls in the morning, so we thought the afternoon was better.

Ethan Bellamy – Wunderlich Securities

Let's stick on the NGL issue. What are you seeing so far in the third quarter with respect to NGLs relative to crude realizations?

Steve Pruett

You know we're a little bit early there, I don't think we finished – our Chief Accounting Officer's shaking his head. We haven't finished our accruals, but generally the trend is getting slightly better and what with this really, at least, record low spread. You know historically NGLs, from my 20-plus year history, has been around 65% of a basket of NGLs vis-à-vis crude.

It bottomed out at just below 50%. It peaked at about 80% last fall, which was very nice while we had it, and we're hopeful that it's moving back towards 60%. But the last, I think June, we were still in the 53 percent range comparing our basket of NGL to that of WTI. So there's still room for improvement, and directional improvement, and hopefully continued improvement

What we read, and you read the same things, and it's the PetChem market is improving so ethane and propane are desirous. It got so cheap here in the states, that we – the [ethane] crackers are able to export product, which is pretty astounding to me. It's the first time I've seen that in years; that we can compete internationally with petrochemical exports.

Ethan Bellamy – Wunderlich Securities

Okay, I appreciate that Steve. Is 7% still a good number to use as the weighted average natural decline rate across all your wealth?

Steve Pruett

Oh my, that's a tough one. It's been in the 6% to 8% range, that's probably a pretty good –

Cary Brown

I think that's a good basin decline. It gets a little bit – when we do a lot of drilling, it gets a little steeper than that, but for good solid Permian assets like we have, that's what you're looking at as an overall decline in this basin.

Steve Pruett

That's a good question. Ethan, when you looked at our year-end reserve report, our decline appeared to accelerate and certainly what was reported was an acceleration of that. It was primarily because you had $44.00 year-end oil prices juxtaposed to say a $20.00 listing cost for the average of 2008, which was in the $100 oil price environment.

We had a lot of wells that were calculated to be uneconomic, and so as those wells hit their economic limit in our SEC reserves, it caused a steeper decline than as a natural decline, and with the restoration of reasonable oil prices, against lower listing cost, we ought to report something that is more akin to our 6% to 8% PDP decline the end of this year.

Ethan Bellamy – Wunderlich Securities

One last question, it looks like you're reaching out a little bit further with the hedge book. Is that a philosophical change we expect you guys to hedge more of the production further out as we go forward?

Cary Brown

We ask that question every day. What's the right answer? I'll tell you as you become uncomfortable with where the banks are going, you want to hedge further out because you want to protect your borrowing base as you – I think at Legacy we're still very, very bullish long term on oil prices.

So there's a balance that we're walking between managing our risk portfolio, and as you see we've done a good job with that by being able to maintain distributions, and our cost of capital, because if you lose borrowing base you've got to go issue equities. So we'll watch the banks and we’ll kind of watch and put all that into a mix to make a decision.

That's a long answer to a short question, but we're looking at it every day. I wouldn't expect you to see us materially go out further if you didn't see the banks start lowering price [decks]. But we gain a lot of borrowing base when we add on hedges. It's $85.00 out there in the outer years and banks are running $60, $65, and you can gain a lot of borrowing base by adding hedges.

Operator

And we have a follow-up question from Michael Hall – Stifel Nicolaus & Co.

Michael Hall – Stifel Nicolaus & Co.

Thanks for the follow-up, guys. Just real quickly and I think you made a comment and I just want to make sure I caught it right, about production growth? It sounded kind of like third quarter down another 2%? Did I hear that right? And then maybe flattish in the fourth quarter from there?

Cary Brown

What we did is we made the decision that we're definitely not going to try chase peak production. The more you drill, the steeper those declines get and the more you have to spend on CapEx. So if we were sitting here trying to defend an 8,500 barrel a day number, we'd have to spend more CapEx. The more CapEx we spend the steeper that decline gets.

So what I'm saying is if we decline another 2% it is not going to surprise me. We’re not going to chase that number. We don't expect dramatic declines, but we think we'll fill in with acquisitions, and as the capital we're spending is more productive, when it costs you 30% less to drill the same well it goes further, too. So I think I wouldn't be surprised if we see decline in the third and fourth quarter. I wouldn't be surprised if it stayed flat.

Michael Hall – Stifel Nicolaus & Co.

Okay, maybe down 2% to flat is a decent way for me to think about it?

Cary Brown

I'd say that's a reasonable way to think about it.

Michael Hall – Stifel Nicolaus & Co.

And then you talked about going to the board for additional spending. Care to outline any of the projects you're thinking about just generally?

Cary Brown

We were – it made so much sense to spend money drilling the second half of last year with prices where they were that we had some recompletion kind of work that we've kind of been throttling back because we were doing some drilling. That kind of work goes a long way. You'll see us do more of that. I don't think you'll see us jump out there with a big drilling program, although we will do some drilling in the second half of the year.

But we don't have that project where you've got 500 rig completions. It's a well here, a well there and just blocking and tackling; the kind of stuff we always do.

Operator

Our next question is from Yves Siegel – Credit Suisse.

Yves Siegel – Credit Suisse

Not to belabor a point, but could you describe what you did on the development capital side? It just might be semantics, but what kind of activity made up that $2.6 million? Was that, again, just recompletions and stuff?

Paul Horne

You're talking about the second quarter of CapEx?

Yves Siegel – Credit Suisse

Yes, sir.

Paul Horne

Yes, it was primarily recompletions. We had a completion activity in a well we drilled Q1 and completed it in Q2 and then a non-operated interest well in Q2, so it was a combination of drilling and completions, recompletions, but $2.6 million, that is an extremely low quarterly number for us. We were doing that for very obvious reasons with the Q1 product prices that we had just experienced and the results being less than what we had predicted in Q1. So we were trying to make sure that we didn't get out over our skis in Q2.

Cary Brown

Let me – the drilling results have been on par with expectations. It's the price that's been less than what we thought it was going to be when we did some of this drilling, so our results look just what we'd expect them to look like.

Paul Horne

Absolutely.

Steve Pruett

Yes, we had an excellent Wolf Camp well and East Binger well, that's our nitrogen, miscible nitrogen project in Oklahoma. In second quarter both wells have performed very, very well. They're 50% plus 14 interest. I think we have a couple more of those to drill in the fourth quarter. So I'm really pleased with the inventory of behind pipe opportunities Paul and his team have put together that we can exploit really in the last four months of the year. It's about a $6 million inventory with a very high rate of return projects in existing well bores. That's obviously the most productive use of our capital.

Operator

Our next question is from Richard Dearnley – Longport Partners.

Richard Dearnley – Longport Partners

What was the nature of the conflict that got in the way of the Apollo deal?

Cary Brown

I don't think there was any conflict. Apollo had made an offer and if you were thinking that prices were going to stay low and in an environment – if you look at the first quarter we had probably I'd say a likelihood of oil staying at $40 and the banks did what they might have done, we probably were going to have to cut distributions and in that scenario it might have made sense to do something with Apollo.

I think as it played out and the board looked at our build forward scenario and where the banks were going to be and where prices were, it just didn't make sense at the numbers they were offering and I think they didn't want to increase the offer to a level that the board thought made sense.

Richard Dearnley – Longport Partners

I was keying off of the press release that said that, it was – oh, I forget.

Cary Brown

Oh, the Conflicts Committee? No, anytime that management's going to stay on, and Apollo was definitely not going to buy Legacy if management didn't stay on and so we had agreed as management that if the board reached a deal with Apollo that we would – we thought we would be able to work with Apollo.

As it worked out, and that was the conflict, if we stay on in theory there's a conflict between what management wanted and what's best for the company.

Steve Pruett

Basically management had an opportunity but the investors wouldn't have had, so we had to have independent directors determine one, the fairness of the offer and manage the process with independent financial advisors and legal advisors.

Operator

That does conclude our question and answer session. I'd like to turn the call back over to Mr. Brown and Mr. Pruett for any additional or closing remarks.

Cary Brown

I just want to say thanks again to our unitholders and I am real pleased with how things have turned out. We're excited we're back in the game of looking at acquisitions, looking at doing what we were built to do and it looks like we weathered a pretty good story and my expectation is that we'll continue on this path and it'll be a good path.

So for those of our unitholders that have stayed with us through the good and the bad, I appreciate that and we'll try to continue forward and grow those distributions and continue to grow value for our unitholders.

Steve Pruett

As a last comment from me, we will be paying a $0.52 distribution on August 14th, so the proverbial check will be in the mail or the wire will be coming over to you soon if you're an investor.

Operator

That does conclude today's conference call and we thank you for your participation.

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!