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Legacy Reserves LP (NASDAQ:LGCY)

Q3 2012 Earnings Call

October 31, 2012 10:00 am ET

Executives

James Daniel Westcott – Executive Vice President and Chief Financial Officer

Cary D. Brown – Chairman, President and Chief Executive Officer

Paul T. Horne – Executive Vice President, Chief Operating Officer

Micah C. Foster – Chief Accounting Officer and Controller

Analysts

Kevin Smith – Raymond James

Ethan Bellamy – Robert W. Baird & Co., Inc.

John Ragozzino – RBC Capital Markets

Praneeth Satish – Wells Fargo Securities, Llc

Michael Peterson – Mcnicoll, Lewis, & Vlak

Daniel Guffey – Stifel Nicolaus

Matt Niblack – HITE Hedge Asset Management LLC

Operator

Ladies and gentlemen, thank you for standing by and welcome to the Legacy Reserves Third Quarter Results Conference Call. Your speakers for today are Cary Brown, Chairman, President and Chief Executive Officer; and Dan Westcott, Executive Vice 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, October 31, 2012.

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

James Daniel Westcott

Good morning, and welcome to Legacy’s third quarter earnings call. Before we begin, I’d like to remind everyone 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 statements as defined by Securities Laws.

These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions. Actual results may differ materially from those discussed in these forward-looking statements and you should refer to additional information contained in Legacy’s to be filed 10-Q for the quarter ended September 30 and subsequent reports as filed with the Securities and Exchange Commission.

Legacy is an independent oil and 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 call over to Cary Brown, Legacy’s Chairman, President and Chief Executive Officer.

Cary D. Brown

Thanks, Dan, and thanks to our friends and unitholders for joining us today. I am excited to have Dan Westcott with us for the first time on our earnings call. Dan is our new CFO. He joined us in late September and since ground running and really excited to introduce him.

Dan’s background was with J.P. Morgan and then also most recently with GSO, Blackstone where he was in the energy group dealing with all kinds of energy, private energy investments and public equities. I’m really excited to have Dan to join our team. And I think he has a great cultural fit and bring some skills to us as we move into new phase or a phase of our business where I think we’re going to be doing some bigger acquisitions and continue to do what we have done in the past. So Dan, welcome and perhaps I introduce him to you guys.

Let’s talk about third quarter, we had a strong operational quarter where we had record production for the quarter based on just the overall acquisition efforts and our capital program. We had expenses that were a little higher than we anticipated and we looked into those a little bit, dug a little deeper and found out that that look like our base expenses are going – it’s not like an inflationary cycle where you’ll see a soon change, but we have had some pretty significant remediate work over this quarter that we don’t expect to be ongoing. And so we expect those expenses to come back in line.

We also had adjusted EBITDA of $49.3 million, which increased 21% over the quarter. We saw differentials move back into normal. We talked about that last quarter, where we had some issues on the Permian differentials, those are coming back to normal and that was encouraging and helped us with our EBITDA.

On the development front, we invested $19.6 million in our capital program. Most of that’s all away, we are very encouraged still with our Wolfberry drilling, our Wolfbone drilling is ongoing now and I think that’s good. Our Bone Spring is ongoing and then we also have some encouraging results from our non-operated projects. With that, we decided to increase our capital program from $62 million to $66 million. We believe this will create some organic growth and feel real good about where we are spending our capital.

We reported $23.4 million or $0.49 a unit in distributable cash flow, covering our $0.565 quarterly distribution 0.87 times. You will see we did increase distributions, but if you look at our capital, we spent 40% of EBITDA back in the ground this quarter, which negatively hit our distributable cash flow.

If you look at it, we talked about 20% to 30% is the range that it takes the whole production flat. We don’t report a maintenance CapEx and that’s because we don’t want to get boxed in any one number because it’s not exactly a knowable number. But if you look at a 30% number, we would have covered our distribution 1.04 times. And so we feel pretty good about where we’re headed and what we’re doing there.

We’re encouraged – probably as encouraged as I’ve ever been on the acquisition front. We’ve got more to look at right now that I think fits us, much of it needs to close by the end of the year. You look at markets where you have few deals and lots of buyers’, it looks like right now there’s lots of deals and so all the buyers can’t line up on one deal. They’re spread out and that’s when you have an opportunity to make some acquisitions. And I will be real surprised if we don’t get some meaningful acquisitions done between now and the end of the year.

So I am very encouraged about where we’re looking on our acquisition front and operationally. So if you look at all of that combined, we feel good about even a distribution increase raise it from $0.56 to $0.565, that’s a 3.7% raise over the year, and feel good about where we’re going forward – our outlook going forward.

So with that, I’ll turn it over to Dan to talk about the individual results and how we did our more detail results.

James Daniel Westcott

Thanks, Cary. It’s a pleasure being here this morning with you all on the phone. I am excited to be have joined this team here at Legacy and I look forward to working with this great management team as we work to grow both the company and for the benefit of our unitholders.

As Cary mentioned, we are very pleased with our third quarter results. We increased our production to record levels, produced strong financial results, continued to invest in attractive oil drilling projects, and closed additional accretive acquisitions.

On October 1, our 14-member bank group redetermined our borrowing base at $600 million. And as of October 30, we have a debt balance of $462 million, leaving us approximately $138 million of current availability under our credit agreement. With the support of our banks and a strong public equity and debt capital markets, we are confident in our ability to finance our upcoming capital needs.

We are pleased to report un-audited preliminary financial information extracted from our 10-Q. I will go ahead and make some comparisons to the third quarter results relative to second quarter and the information contained in this earnings release is more – fulsomely described in our to-be-filed 10-Q.

Highlights for the quarter, as I mentioned, production increased 3% to 14,772 Boe per day in the third quarter, primarily driven by a full quarter impact of approximately $105 million and $8 million of acquisitions of producing properties during the second and third quarters respectively.

Our third quarter production was again negatively impacted by high pressures in natural gas gathering lines in the Permian Basin primarily due to the extensive development in the area. Average realized prices, excluding commodity derivatives, were $61.95 per Boe in the third quarter, and that's up 2% from $60.85 per Boe in the second quarter. Average realized oil prices increased $0.27 from $83.27.

And while we saw WTI decline slightly during the quarter, about $1.07 per barrel, our oil differential decreased by a larger amount, about $1.33 a barrel, resulting in slightly higher realized prices. These decreased differentials were primarily driven by a Midland-to-Cushing differential that averaged $1.75 during the quarter, we talked about that at length last quarter, which averaged $4.91 for the second quarter. This decrease in Midland-to-Cushing differential was partially offset by a full quarter impact of our acquisitions in the Rockies. Those properties typically have a higher crude oil differential than our properties in the Permian Basin.

In addition, average realized prices increased on the natural gas side about $0.23 to $4.10, and average NGL prices decreased $0.06 to $0.91 a gallon. As a reminder, our average realized natural gas prices are favorably impacted by NGL content in our Permian Basin natural gas.

Oil, NGL, and natural gas sales, excluding derivatives, were $84.2 million in the third quarter. That’s an increase of 6% from $79.2 million in the second quarter, and that’s due primarily to higher production and slightly higher realized commodity prices.

Production expenses excluding taxes increased 18% to $28.2 million in the third quarter from $23.9 million in the second quarter due to both our recent acquisitions as well as higher remedial workover and non-recurring expenses.

Workover expenses during the third quarter, which were primarily casing repairs and repairs or replacements of submersible pumps, totaled $3.5 million, or approximately $2 million higher than our total in the second quarter. Production expenses per Boe increased 13% to $20.76 per Boe as compared to $18.35 in the second quarter.

Legacy's general and administrative expenses were $7 million as compared to $5.2 million last quarter. Of note, about $2.1 million of the $7 million was non-cash unit based compensation as our unit price increased $3.91 during the quarter.

Cash settlements received from our commodity derivative during the third quarter were $6.1 million compared to $2.0 million paid during the second quarter. As a reminder, we talked about this last, our quarter crude oil hedges settled during the month after the corresponding volumes are hedged.

Cary mentioned earlier, adjusted EBITDA after the quarter increased 21% to $49.3 million due primarily to higher production, slightly higher realized commodity prices, and $2.7 million positive oil hedge lag effect. Adjusted EBITDA for the third quarter was further impacted by remedial workover and other non-recurring expenses that resulted in higher production expenses.

Development capital increased 17%, $19.6 million in the third quarter from $16.7 million in the second quarter making it the second highest quarter for development capital expenditures in Legacy’s history. This increase was driven by a full quarter of our Wolfberry drilling program as well as partial drilling costs from our operated horizontal Bone Spring well from which we should realize production during the latter half of the fourth quarter.

Distributable cash flow increased to $23.4 million in the third quarter compared to $19.1 million in the second quarter. This increase was due to significantly higher adjusted EBITDA that was partially offset by higher development capital, higher cash settlements paid to non-executive employees on our LTIP unit awards, and slightly higher cash interest expense.

We incurred a net loss of $23.6 million for the quarter, or $0.49 per unit, and includes unrealized losses of $33.3 million on our commodity derivatives and a $7.3 million impairment charge on our oil and natural gas properties. This compared to net income of $82.9 million, or $1.73 per unit, in the second quarter, which included unrealized gains of $84 million on our commodity derivatives and $14 million impairment charge on our oil and natural gas properties.

So that concludes our prepared session. We’d encourage you to review our earnings release and read our Risk Factors and other more detailed disclosures and our to-be-filed 10-Q.

At this time, I would like to turn it over to the operator to open it up for Q&A.

Question-and-Answer Session

Operator

(Operator instructions) Our first question comes from Kevin Smith from Raymond James. Your line is open.

Kevin Smith – Raymond James

Hi, good morning.

Cary D. Brown

Good morning, Kevin.

Kevin Smith – Raymond James

Cary, can you talk about the increased CapEx budget that $4 million, is there something else that new projects you are going to be taken on or is that really kind of cost creep from other existing projects?

Cary D. Brown

That’s not – we are not seeing our AFEs go up. That’s more activity. Paul…

James Daniel Westcott

Yeah. I’ll turn that over to Paul Horne.

Paul T. Horne

Sure. Hey, Kevin.

Kevin Smith – Raymond James

Hey, Paul.

Paul T. Horne

No. It’s not a matter of what were expenditures. It’s a matter of exactly what we told you guys, we kind of gave you a heads up on this last call that we expected our CapEx budget to go up due to drilling and completion of our horizontal Bone Springs well that’s operated and another significant non-operated position in the drilling on additional horizontal Bone Springs well. As well as our Wolfberry rig has – especially, in the third quarter, we set two different records while drilling, speed of drilling and getting down and completing the well. And when you do that, you just get more wells drilled than your original schedule had. So it is addition of property – of projects. It’s addition of good projects that we are choosing to do now. We could have delayed it in the future years, but felt like they were good projects and we have to go ahead and get them done.

Cary D. Brown

So the short answer Kevin is, if you’re drilling wells faster, you’re going to get more wells in on the year and you don’t save enough by drilling them faster to offset what it cost to frac two more wells and set pipe on two more wells.

Kevin Smith – Raymond James

Got you. So its combination of a new non-op horizontal Bone Springs well and then faster more Wolfberry wells. Is that fair?

Cary D. Brown

Yes.

Paul T. Horne

Yes.

Kevin Smith – Raymond James

Okay. And then if you wouldn’t mind just chatting a little bit about your operating costs, I know the workover expense creeped up this quarter, but when I pulled that out, it still seems like the base level is higher than the second quarter’s level. I mean I know you acquired some Rockies properties that typically have a highest cost. But what do you think your kind of base level cost rate is at this point?

Paul T. Horne

You just answered the question for me Kevin. Obviously, we made – the majority of our acquisitions in 2012 in the Rockies, which is a higher cost structure generally about $5 a Boe we have than the Permian. So we expect it our lifting cost to go up due to those acquisitions, but the big thing in Q3 was we just had a significant amount of non-recurring remedial well work with those jobs.

We always have some wells that normally in a quarter were in the $1.25 million to $1.75 million range. And we were more than double that in Q3 and it was – we’ve looked at that in detail to make sure they did not come to acquisition maybe we – we’ve concerned that maybe we’ve made an acquisition where the prior operators haven’t had a good chemical program and taking care of the well bores and were having unusually high failure rates that’s not the case, it was kind of just gathered across our asset base, but it was unusually high.

We were running in the $18 to $18.50 of Boe range with the $110 million of Rockies property that is on this year. I would expect that to be in the low 19 range on a go-forward basis without the unusual non-recurring quarter that we had.

Kevin Smith – Raymond James

Okay. Perfect. And then lastly and I will jump off. Given organic growth rate you guys are kind of targeting is based at this kind of levels of spending?

Cary D. Brown

Kevin, the answer is no. We don’t have an organic growth rate. We target, we try to make good business decisions with what’s in front of us and as we have projects that are tougher to delay, we would like to be in that 30% – 20% to 30% going back in the ground. But we’re not going to – as I’ve said before, we’re not going to chase coverage in ways that looks like we’re making bad business decisions and shutting the rig down again to try to stay in coverage, it doesn’t look like a good business decision to me right now. You need to have the efficiencies of running a rig full time and then the Bone Springs well that’s coming in, that’s just a pretty expensive well you’re talking about, $5 million, $6 million well.

Cary D. Brown

So we’re doing that. And you don’t want to shut everything else down just to do that. So it’s going to be kind of lumpy, but I would say, you can expect single-digit organic growth when we get above 30%. And the question is, how do you figure that, and you figure that on what’s happening next month, it may be higher than that, as you said, factor that over the next year. It might be right in that range, if you factor it over the next 20 years; you got to start looking at this. So that’s why we try to avoid the trap of which is which, but we’ve been pretty comfortable that it’s somewhere in the single-digit growth range.

Kevin Smith – Raymond James

Okay. Thank you so much.

Operator

Thank you. Our next question comes from Ethan Bellamy from Baird & Associates. Your line is open.

Cary D. Brown

Good morning, Ethan.

Ethan Bellamy – Robert W. Baird & Co., Inc.

Good morning, Cary. A couple of questions for you. What’s on your play right now in terms of the A&D and what’s the likelihood we see you acquire something else before year-end?

Cary D. Brown

I would say it’s pretty likely. You are going to see us acquire some by year-end. You never – we have a lot that we’re looking ahead and in negotiations with, Ethan, but they never shot till they are shot and I’d be real disappointed if we don’t have some significant acquisitions to endure in.

Ethan Bellamy – Robert W. Baird & Co., Inc.

Okay. That’s helpful. When you think about acquisitions, price per barrel, how does that stack up against say your F&D costs for Wolfberry drilling?

Cary D. Brown

Drilling is going to be better. Always the internal capital projects we have are better rate of return than we’re going to have (inaudible). What you’re looking at though is the acquisitions are going to have a different decline than brand new drilling program wells do. And so – and you can do acquisitions on scale. So with the capital markets as open as they are right now and the acquisition opportunities, we feel real good about the chances of doing some really significant acquisitions.

Ethan Bellamy – Robert W. Baird & Co., Inc.

That’s a good segue to my next question, which is what is – with the Wolfberry drilling, what is the weighted average decline rate on the total asset portfolio now maybe for the next year and then kind of long-term? Don’t give me that 5% to 10% number you gave me before?

Cary D. Brown

That’s a really good number.

Ethan Bellamy – Robert W. Baird & Co., Inc.

I hate that answer.

Paul T. Horne

We’ve looked, Ethan, there is a lot of things going on in that and you can see early declines as high as – even on at a company level, as high as 10% to 12% right after you bring wells on, but when we look at our entire asset base and look at our reserve report, we’re not seeing overall company declines that high in 2013, which same as your question here, probably looking at what you want to put in your model for early ’13. I think in the high single digits to 10%, 11% early and flatten out pretty quickly down in the 7%, 8% range 18 months, three years out. And then you can get down in the bottom end of your range, if you start looking three or four years out. So, the 5% to 10% is actually all correct. It just depends on what point in time do you want to looked at it.

Ethan Bellamy – Robert W. Baird & Co., Inc.

Got it. Fair enough. And then finally, anything interesting out of decline or the FireWheel relationship?

Cary D. Brown

The early results were very encouraging. Ethan, we get – the first well was not a great well. It was definitely a commercial well, still making about 150 barrels a day. The second well and it will get about a week or two production is making right at 800 barrels a day oil and another 2 million gas. So, it looks real encouraging over there right now. But those are early rates, but I would say, that second well is setting up for a pretty good program and they’re trying to figure out what’s the difference in the first one and the second one.

Ethan Bellamy – Robert W. Baird & Co., Inc.

All right. I appreciate it. Thanks gentlemen. Good luck.

Cary D. Brown

Thank you, Ethan.

Operator

Thank you. Our next question comes from John Ragozzino from RBC Capital Markets. Your line is open.

John Ragozzino – RBC Capital Markets

Good morning folks.

Cary D. Brown

Good morning, John.

James Daniel Westcott

Hey, John.

John Ragozzino – RBC Capital Markets

Can you elaborate a little bit more on the line pressure issues that you’ve discussed in the Permian Basin?

Cary D. Brown

Sure. We’ve talked about this for several quarters now. What you’re seeing is, there is so much development activity in the Permian. If you’re in the middle of the Wolfberry that’s what you’re drilling which we are. We’re not the only ones drilling in that area. And so all of our competitors as well as our sellers are bringing on high rate wells with high initial gas rates which just increases the line pressure you’re seeing.

Early on, what you saw, a lot of the operators doing was a putting field compression on lease. And so if one company puts field compression in, then everybody else puts field compression in. And then you’re fighting the same battle once everybody gets there. So that’s only a short-term pitch.

What we’re looking to, is the gas gathering companies to fix their bottleneck issues and get those lined out in areas we’ve seen that, John, and things have gotten better. And then there will be a number of wells come on in another area. And so I think it’s a situation that the industry is working on and improving, but it just continues to be an ongoing issue, although it is moving around somewhat. It’s not for registry, it’s not that we can’t sell our gas even though it is liquids-rich and we get a nice bump on the price of that gas. The effect is those higher pressures, back all the way up to the well head and hold back pressure on the oil production as well until dig it. It has continued to impact our production, but we’re seeing progress and improvement.

If you notice, I’m a little reluctant to say that, because I said that the last quarter and I said that the quarter before that, which is true. It just seems like when we get a second curve in one area, it pops up in another area. So, it’s a good thing. It means that the Permian is hot, there is a lot of activity, and there is a lot of work going on. It also means that the gas gathering companies are having to spend a good bit of money to alleviate those issues.

James Daniel Westcott

And in effect that means that, if we’re producing less, they’re running less than their plans. So they’re working real hard to fix it, and it will fix, it gets fixed in one area at a time and takes a little bit of time.

John Ragozzino – RBC Capital Markets

All right, thanks. And that kind of leads into the next question, can you give me a better feel for company-wide, what the nat gas uplift, including all the Permian production is on a company-wide basis, so the Btu content, kind of what are you seeing above, of course, in Henry Hub prices?

James Daniel Westcott

We referenced $4.10 in Mcf realized price excluding commodity hedges. So, that should give you a good sense. I think for the quarter, Henry Hub averaged 276, so that’s 49% above the index.

John Ragozzino – RBC Capital Markets

And that’s a fair run rate going forward, you think?

James Daniel Westcott

Yes.

John Ragozzino – RBC Capital Markets

Can you explain what the impairment charge was related real quickly?

Micah C. Foster

Yeah. This is Micah Foster. The majority of the impairment charges for the quarter is about $6.5 million. It was related to an asset that we’ve entered into an auction agreement with the third-party to sell them the net asset. So, we believe that likelihood of they will exercise that option is high. So we’ve essentially written that asset down to its fair market value. The remaining 800,000 was just some – a couple of small impairments on – in a couple of different fields related to slightly decreased oil prices.

John Ragozzino – RBC Capital Markets

Sorry, and then one more for Mr. Dan, just believing he has been doing his homework. On the non-cash stock-comp expense, can you give us a feel for the quarter-on-quarter trends whether you know, there is going to be a bump in the first or the fourth or how does this plan out for the rest of the year?

James Daniel Westcott

Yeah. It’s all driven by unit price. So for the quarter, we were up, almost $4 during the quarter. So we hope that’s a big number. I like seeing a big number every quarter, how about that.

John Ragozzino – RBC Capital Markets

Okay. The bonuses that are paid at the end of the year are just timing of certain expenditures?

James Daniel Westcott

That’s all – so to be clear, that’s all non-cash. The cash component that you’ll see in the calculation in the back of the release as it relates to discretionary cash flow is the exercise of non-executive unit awards. Those are UAR exercises and so there’s – it’s an auction agreement, a cash settlement based on the difference between exercised price and the current price, but those are cash, the $2.1 million that we referenced is non cash.

John Ragozzino – RBC Capital Markets

Okay, that’s very helpful. And then finally, any expectation on the Bone Springs well in terms of targeted IPs, brining UAR, you mentioned that $6.5 million AFV, so --

Cary D. Brown

Yeah, as you know, we generally don’t give guidance on expectations. What we have told you in past quarters is the first Horizontal Bone Springs well that we drilled on that lease last year, performed very well, came in at nice happy rates and has maintained good solid production for over a year and a half and great rates of return, so --

James Daniel Westcott

That’s similar to our Wolfberry rates returns. It’s more expensive, maybe a little higher than Wolfberry, but not dramatically higher at all.

Cary D. Brown

No, not dramatically higher rates of return. I mean it’s a great yielding program. We’re excited about it. Generally in the industry, I’ll give you a little more help in that, if you look industry wide you see those Bones Spring’s horizontal wells coming in the 250 to 750 barrel oil per day range.

John Ragozzino – RBC Capital Markets

And barrels are down (inaudible) before you done it?

Cary D. Brown

Good, not so happy and expect year later, but it will still be making 100 barrels a day kind of rates or better.

John Ragozzino – RBC Capital Markets

All right. Thank you very much gentlemen.

Cary D. Brown

Thanks, John. I appreciate it.

Operator

Thank you. Our next question comes from Praneeth Satish from Wells Fargo. Your line is open.

Praneeth Satish – Wells Fargo Securities, Llc

Hey, guys. Good morning. Just two quick questions from me. On the acquisition front, just wondering if you’re seeing more opportunities on the gas side or oil side? And also, are you seeing cash flow multiples increase at all from where they were at the beginning of the year?

Cary D. Brown

Answer would be, we’re looking – chasing more oil weighted opportunities at the moment than gas weighted opportunities. And I would expect that the cash flow multiples on bigger deals are going to be a little higher than what we have historically done on smaller deals. So it depends on what size of deal we’re looking at. And so this year, I think we’ve been in the 5.5 times cash flow kind of number. If you did a big deal, I think it will be more. I don’t think it will be eight, I think it will be 6.5% or something like that.

Praneeth Satish – Wells Fargo Securities, Llc

Okay. And one more question from me. I know it’s early, but as we look at 2013, I mean, can we assume CapEx spending will be similar to 2013 levels. Should we anticipate any big changes there?

James Daniel Westcott

We wouldn’t anticipate big changes there. We got to try to stay in this 30% or so of EBITDA.

Praneeth Satish – Wells Fargo Securities, Llc

Okay. Great. Thank you.

Cary D. Brown

The only thing, I’d add there is that CapEx program gets approved by the board.

Praneeth Satish – Wells Fargo Securities, Llc

You haven’t

James Daniel Westcott

Yeah, right.

Praneeth Satish – Wells Fargo Securities, Llc

Great. Thanks.

Operator

Thank you. Our next question comes from Michael Peterson from MLV. Your line is open.

Michael Peterson – Mcnicoll, Lewis, & Vlak

Hi. Good morning, gentlemen. How are you?

James Daniel Westcott

Good morning, Michael.

Cary D. Brown

Great, Michael.

Michael Peterson – Mcnicoll, Lewis, & Vlak

I wanted to talk a little about your available credits. I kind of expected with the October re-determination that you’d get more of an uplift than the $35 million that you did, I was thinking maybe something in the $60 million to $70 million range based on the assets that you had dropped in since your last evaluation. How did that fit with your expectations?

Cary D. Brown

Part of the issue there is the run-off of hedges, and so we had some high dollar hedges run-offs that as you roll forward six months and not able to replace those. We had some pretty high hedges in there and the banks run a pretty low price tag, but it was – I don’t know, but I’d say better than what we thought.

James Daniel Westcott

Yeah. I think $600 million is consistent with our expectations for quarter. As we noted, we have $462 million drawn, with $138 million of availability. With the $66 million capital program that we feel comfortable at that level at the moment.

Michael Peterson – Mcnicoll, Lewis, & Vlak

Okay. Thanks for that Dan. Now both in the press release as well as your comments thus far this morning, you’ve alluded to a pretty prospective A&D market. Do you have an expectation that you’re going to see prospects that materialize such that you might need to look beyond the available credit and if so, what options might you consider as we head into year end?

James Daniel Westcott

The answer is, absolutely I think that it’s a great time to be going in high yield market. And so probably we won’t go to high yield market without a significant acquisition, but we’d expect that with a significant acquisition, sure it makes sense to add that arrow to our quiver and my expectation would be that that on a significant acquisition we would increase our liquidity by both equity and high yield.

Michael Peterson – Mcnicoll, Lewis, & Vlak

Okay, so thank you, sir.

Cary D. Brown

Michael, the only thing I’d say is, we’ve talked about high yields in past conference calls. So I think the stance remains similar to where we were last quarter as a company, and I assume you see that market and see that it is an attractive market. But I guess I would – our position remains unchanged.

Michael Peterson – Mcnicoll, Lewis, & Vlak

Okay, okay. Thank you. Once last one Dan, borrowing rate during the period?

James Daniel Westcott

As far as the average effective interest rate?

Michael Peterson – Mcnicoll, Lewis, & Vlak

Yes, sir.

James Daniel Westcott

I think, we were just under 3% to 2.75% effective there. So that’s excluding our $364 million of interest rate.

Michael Peterson – Mcnicoll, Lewis, & Vlak

Okay. Thank you very much, guys.

Cary D. Brown

You bet.

James Daniel Westcott

Thanks, Michael.

Operator

Thank you. (Operator instructions) Our next question comes from Daniel Guffey from Stifel Nicolaus. Your line is open.

Daniel Guffey – Stifel Nicolaus

Hi, guys.

Cary D. Brown

Hi, Daniel.

Daniel Guffey – Stifel Nicolaus

Hi, just a couple of Bone Spring clarifications, well that you expect to bring in latter half of fourth quarter that’s – you have an 85% working interest in that well, is that right?

Cary D. Brown

Well, that actually recently changed. We part of an acquisition that we made had additional working interest in it, which took us from – it increased the cost-to-capital about $1.1 million. I think, about 66% to 80%.

James Daniel Westcott

Yeah, I was thinking particularly in the oil wells.

Cary D. Brown

That’s what I would think.

Daniel Guffey – Stifel Nicolaus

Okay.

James Daniel Westcott

I can’t remember off the top of my head, because that acquisition came in, but we owned – but for significant piece of...

Cary D. Brown

Yeah. 68% and we have about 13% to 14% in that acquisition outlook.

Daniel Guffey – Stifel Nicolaus

Okay.

Cary D. Brown

We finished drilling that well. We actually fracked it in the previous two days, so the well is fracked and we’re going to be getting on at first week in November and drilling floods out and hopefully we will start seeing oil production by mid to like November. So we’re excited about that and looking forward to seeing the results. And we also have pretty significant piece on the non-op Horizontal Bone Springs well that was drilled in the third quarter and will be completed and fracked it out, I believe this completion is, this week as well.

Daniel Guffey – Stifel Nicolaus

Okay. What’s your working interest in that non-op well?

James Daniel Westcott

I have to calculate it. Hold on. I know what my capital cost was, and I know what the total AFV was, let me – at 20%.

Daniel Guffey – Stifel Nicolaus

Okay. We can expect that sometime early December, sounds like?

James Daniel Westcott

Yeah. I would expect them both to become (inaudible) last half of November versus December. We’ll have a significant impact for the year, but it will sure set us up nicely and impact Ethan’s initial decline rate question that he was just talking about. I hope the decline rate of the company changes dramatically because of those opportunities.

Daniel Guffey – Stifel Nicolaus

Yeah. That will be good. And then, did you guys let the rig go after finishing most recent operated well. When you – I mean, I guess also when do you expect to bring one back?

Cary D. Brown

The Bone Spring well, yes. Of course, we have our Wolfberry one rig program continuing. We have gone through our 2013 capital budget in detail at this point. Assuming that we see the results we’re expecting and the results that we saw from first well, that we drilled last year. I would anticipate drilling another well or two in horizontal Bone Springs wells in 2013, but not anywhere near really to say here, to suggest that we’re expected timing of that at this point.

Daniel Guffey – Stifel Nicolaus

And I guess is your focus going to be on same leases that you’ve currently drilled, where the Lea units are?

Cary D. Brown

Yeah, very good question. We’ve got several opportunities all in the same general area, but on about five different leases. And I would expect us to probably move over and drill a couple of wells off of the Lea unit and on a couple of those other leases. Not because we need to prove it up, it’s being proved up as we speak, but offset operators and drillers that are drilling in the area, but I would expect us to move those on our next well or two.

Daniel Guffey – Stifel Nicolaus

Okay, great. Thank you, gentlemen.

Cary D. Brown

Thanks.

Operator

(Operator instructions) We have a question from – one moment. We have a question from Matt Niblack from HITE Hedge. Your line is open.

Matt Niblack – HITE Hedge Asset Management LLC

Good morning. Just a quick follow up on your expected financing. If I understood correctly, you do not expect to need to access the equity or the high yield markets unless you do a significant acquisition, is that correct?

Cary D. Brown

Yeah. That’s correct.

Matt Niblack – HITE Hedge Asset Management LLC

Great. Thank you.

Operator

Thank you. I show no further questions at this time and would like to turn the conference back to Mr. Cary Brown for closing remarks.

Cary D. Brown

I just want to say, thanks to our unit holders and the analysts who are following us. I appreciate you guys support. If you have any additional questions, feel free to call Dan or anybody here to give you guys good information and we’re looking forward to active next quarter and getting back with you guys following up. Thank you.

Operator

Ladies and gentlemen, thank you for your participation in today’s conference. This does conclude the program and you may all disconnect at this time.

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