Jaime Casas - VP, CFO and Secretary
Eric Mullins - Co-CEO and Chairman
Charlie Adcock - Co-CEO and Director
Tim Miller - VP and COO
LRR Energy (LRE) Q3 2012 Earnings Call November 5, 2012 10:00 AM ET
My name is Crystal and I will be your conference operator today. At this time I would like to welcome everyone to the 2012 third quarter and 2012 results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions) Thank you. Mr. Jaime Casas, you may begin your conference.
Thanks operator and good morning everyone. Welcome to LRR Energy’s third quarter 2012 conference call. Also presenting this morning will be our Co-Chief Executive Officers, Eric Mullins and Adcock and our Chief Operating Officer Tim Miller. Jonathan Hickman our Permian Basin and asset manager is also with us and available for questions. Before I turn the call over to Eric, I first need to provide you with disclosure regarding forward looking statements. Forward looking statements are based on current expectations and relate to future business and financial performance. Actual results and future events could differ materially from those anticipated in such statement.
Forward looking statement involve certain risk and uncertainties and may not prove to be accurate. These risks and uncertainties are included in our risk factor section of our 2011 Form 10-K and our 2012 Form 10-Q on file with the Securities and Exchange Commission. All forward-looking statements are qualified in their entirety by this cautionary statement.
Additionally, during the course of today’s discussion, management will refer to adjusted EBITDA, distributable cash flow and distribution coverage as important metrics for evaluating LRE’s performance. Please note these metrics are non-GAAP financial measures which are reconciled to the most directly comparable GAAP measures in the earnings press release we issued this morning. I will know turn the call over to Eric.
Thanks Jaime and good morning everybody. We appreciate all of you joining us for our third quarter 2012 earnings conference call. We will discuss our operational results in greater detail shortly but in general, we are very pleased with our third quarter. Our strong results led to our increased distribution coverage ratio and increased quarterly distribution for the third quarter.
Specifically, our distribution coverage ratio for the third quarter increased to 1.14 times from 1.06 times for the second quarter and we increased our quarterly distribution for the third quarter by 0.5% to $0.4775 per outstanding unit or $1.91 on an annualized basis.
Additional, highlights for the three months and the September 30th 2012 include average third quarter production of 6,663 BoE per day and EBITDA of $19.5 million both quarterly records for LRE.
As planned, we successfully completed eight new wells in our largest field Red Lake with better than expected initial production results and finally we successfully completed the Nowata #1, sidetrack well at our Pecos Slope field with strong initial production results.
With that I'll turn the call over to Charlie who will talk in more detail about our recent operating activity.
Thanks Eric. I'd like to start by reviewing our operating results for the third quarter. We reported net production of 613,000 Boe for the quarter. Our production was 55% natural gas, 31% oil and 14% natural gas for the third quarter. Primarily due to our 2012 liquids focused development plan, we've increased our liquids production mix from 45%, from 35% during the fourth quarter of 2011. Third quarter production significantly benefited from our active and successful Red Lake field development. Our 15 well, 2012 Red Lake drilling program was completed in August and Tim Miller will go into further detail on the results.
Lease operating and work over expenses were flat from the second quarter to third quarter at $6.9 million or $11.29 per Boe compared to $6.9 million or $11.76 per Boe for the second quarter. LOE was lower on a per barrel basis in the third quarter due to the higher production volumes. We anticipate LOE costs will be lower for the remainder of the year due to less work over activity and lower saltwater disposal cost. During the quarter, we put one saltwater disposal well into service at our Corral Canyon field and we plan to drill, complete another saltwater disposal well at Red Lake during the fourth quarter. Production after long taxes for the quarter were $2 million or $3.24 per Boe. This amount represented approximately 8% of gross revenue compared to 7.5% during the second quarter of 2012. I will now hand the call over to Tim Miller.
Thanks Charlie. During these three months ended September 30th 2012, our cash capital expenditures totaled $13.1 million. At our Red Lake field during the third quarter, we drilled and completed four new wells and completed four wells which were drilled during the second quarter. These wells have average initial production or IP rate of approximately 97 Boe per day, which was a 147% of our expectations. In addition, we successfully recompleted one well, deepened one well and added pay in two other wells at Red Lake. These projects partially contributed to our strong third quarter production performance. We also successfully completed the Nowata #1 sidetrack well in the Bone spring formation at our Pecos Slope field. The Nowata well’s 30 day IP rate was 223 Boe per day which was 288% of our expectation. The Nowata well is predominantly an oil well with approximately 86% of its production is oil, in spite of its listing in the mostly natural gas Pecos Slope field.
Total LRE production continues to be negatively impacted by the curtailment of approximately one million cubic feet per day of gas from our Pecos Slope field. As I stated on our last earnings call, we expect the curtailment to remain at this level until a field wide nitrogen rejection facility becomes operational in January 2013.
The installation of this facility by the gas gathering company is underway. The impact of this curtailment on 2012 total revenues is expected to be less than 1%. The Nowata #1 Side Track well is not affected by the curtailment.
As Charlie mentioned, our 2012 drilling program was completed during the third quarter. Production from the Red Lake field peaked in mid-August. Our remaining 2012 development projects include the completion of the Henry Hub #1 salt water disposal well at Red Lake which was drilled during the third quarter. The well is expected to result in a significant reduction in future salt water disposal expenses. We are also expected to perform one well deepening and four recompletions at Red Lake during the fourth quarter.
We are increasing the low end of our production guidance range from 6,100 Boe to 6,250 Boe per day. Our new guidance range for full year 2012 production is now 6250 Boe to 6400 Boe per day. Our estimated average total production for October was approximately 6,350 Boe per day. We are reaffirming our planned 2012 capital expenditures at approximately $31 million of which approximately $21 million is maintained capital. The remaining $10 million of estimated expenditures is being invested in production growth and cost cutting projects.
I will now turn the call back to Jaime who will walk you through our third quarter financial results.
Thanks Tim, as a reminder, our financial statements and operating results for the nine months ended September 30, 2012 have been recast as if we had owned the assets that we acquired on June 1st, 2012 from Lime Rock Resources since our initial public offering, as the transaction was between entities under common control. Total revenue for the quarter was $9.2 million compared to $40.4 million for the second quarter. Excluding the impact of our hedges, revenue for the third quarter was $24.8 million compared to $22.6 for the second period. The 10% increase in revenue was due to a 6% increase in oil production volumes and a 19% increase in NGL production volumes from the previous quarter.
Offsetting the positive revenue results, average realized NGL sell prices excluding the effect of commodity hedges declined 18%. For the quarter, adjusted EBITDA was $19.5 million compared to $17.7 million for the prior quarter, an increase of 11%. Based on estimated annual maintenance capital for the quarter of $5.25 million, our distributable cash flow was $12.2 million and our distribution coverage was 1.14 times. Regarding distributions, on October 15, we declared a cash distribution for the third quarter of $0.4775 per outstanding unit or a $1.91 on an annualized basis which we expect to make on November 14.
I will now cover details of our commodity hedge program. As a result of our commodity and bases hedges that settled during the quarter, we’ve realized an average natural gas price of $4.85 per MMBTU compared to an average Henry Hub natural gas price of $2.81. And we realized an average crude oil price of $91.49 per barrel compared to an average NYMAX oil price of $92.16.
Subsequent to the quarter close, we further reduced our future exposure to lower commodity prices by adding additional gas hedges in 2017. Assuming the midpoint of our revised 2012 production guidance is held flat through 2017, our total estimated production is 88% hedged for the remainder of 2012, 87% in 2013, 62% in 2014, 56% in 2015, 51% in 2016 and 33% in 2017. Weighted average prices during that period are $93.85 per barrel of oil and $5.09 per MMBTU of natural gas. More specific details of our current hedge position is disclosed in our earning’s press release.
As mentioned before, we are adjusting our previously disclosed production guidance for the full year 2012. We now expect 2012 production to average between 6,250 and 6,400 Boe per day. And we still expect capital expenditures to be $31 million and LOE to average between $10.50 and $11 per Boe for the full year 2012.
Operator, you can now open up the line for questions.
Yes. (Operator instructions) And your first question comes from the line Kevin Smith.
Nice quarter. With your Red Lake production peaking in mid-August, how should we be thinking about production declines for 4Q and possibly 1Q or put it another way, it seems like with October’s rates, when do we think we’ll have the activity level to kind flip some of that declines?
We’re working on our 2013 capital budget as we speak and we will be moving back in to Red Lake obviously to drill in 2013, but we’re not prepared at this point to give any guidance on ‘13 which we will do right after the first of the year. But with the production, it is falling off a little bit, natural decline during the fourth quarter. I think we did explain in the call that we’re guiding maybe more towards the high end of our range now as we close in on the end of the year, so it’s probably how you ought to think about it and then we’ll be coming out with 2013 guidance right after the first of the year.
Okay, thanks. And we’re seeing a lot of Permian operators realize cost inflation this quarter. How you guys kind of guiding down and clearly you saw cost come down or basically flat on LOE side of it. Can you talk about how you’re mitigating some of those costs? How much of it’s really just a factor of lower work hours in 4Q versus kind of systemic offsetting cost (inaudible)?
Actually for the capital for the drilling in the last couple of months, we’ve seen a little bit of weakening in cost particularly on the fracture stimulation side. Obviously as we discussed in the call, one of the things we’re doing to reduce our LOE is drill our own disposable wells to limit our exposure to commercial disposal, salt water disposal. Those costs have been increasing dramatically. In fact they’re probably up close to 60% to 70% in the last year and by drilling our own wells will mitigate a lot of that.
Okay and then lastly, do you guys have any plans, drilling anything else in the Pecos Slope in the next, call it three to six months?
Since we've drilled in the water well, we purchased some free seismic over that area and we're just in the very early stages of evaluating that. So whether or not we drill an offset well, we're very encouraged by those results and looking for opportunities but whether or not we drill will depend a lot on what that 3D seismic tells us.
Our next question comes from Ethan Bellamy.
Two questions for you, first do you expect to be (inaudible) eligible in December or is that more of a first quarter then?
Yes Ethan, I think it would be possible for us to be have a shelf in place by year end. That would assume no SEC review. I think we're assuming and we’re probably is what more likely to happen is that we would be have our shelf in place, early 2013 and hopefully in January.
Okay that's all and with respect to the sponsor, has there been any material changes in that parent and how does it look in terms of total assets suitable for drop down.
We are still very active at the parent of this sponsor level. We have recently signed a couple of additional purchase and sale agreements on properties in the Permian Basin, those haven't closed yet but it's been a very busy market and a very active market and we're continuing to have success. So we're continuing to expand those properties at the sponsor level.
Okay if you maybe a number in terms of Boe that could be available maybe over the next year or so.
No not really in terms of what could be available, as we've said we have about 30 million Boe approved reserves, that's very similar to the 30 million approved Boe's and LRR Energy. Notwithstanding that number being very similar and our production numbers also pretty similar to the production at LRR Energy at 6,500 barrel of oil equivalents per day but if you look at revenues for example just to appreciate the difference between the economic impact of what we have at the sponsor level, we have properties that are producing about a $163 million revenues a year versus the roughly $92 million in revenues that LRR Energy has. So, a much larger economic base of properties at the sponsor level right now even before we had any additional properties which obviously we’re contemplating.
That’s helpful Eric. Just one more question. With respect to G&A that looks little lumpy, is there some maintenance CapEx or G&A lumpiness that’s pretty visible for the fourth quarter or first quarter?
Yes, the second quarter, I guess since (inaudible) of the G&A has been little bit lumpy and there is couple of things, one is in the first and fourth quarter of every you should expect those to be a little bit higher than the second and third quarter because some of our year end cost going through the 10-K process, reserve report process as well as some annual bonuses. Specifically on the third quarter, this quarter was materially lower than the second quarter and that’s because when they did the dropdown transactions in the second quarter, there was probably around $800,000 worth of acquisition cost in the second quarter that were not in the third quarter.
Our next question comes from the line of Michael Peterson.
Hi, good morning gentlemen. With your first anniversary just about a week away, I’m interested in your thoughts, Eric and Charlie, regarding progress in the first year as well as key objectives for the year ahead. Any perspective you might be able to share in terms of acceleration of deal flow, your thought on new basins as well as relative interest in gas or oil would be appreciated.
First of all, yes we are quite happy with obviously second quarter was a strong quarter for us, third quarter was a very strong quarter and particular after the first quarter where we had Red Lake field shut in for 21 days, we’re very happy about that. I think that we are very focused on growing our per unit distribution and in particular as we have said that’s primarily going to come from acquisitions. We’re very happy. We got our first drop down transaction done within the first five months of being public. Our expectation is we’re going to continue either through third party acquisitions or dropdowns or joint acquisitions or transactions from one of our partners. We are very confident that we’re going to find additional acquisitions and continue to be able to grow.
We’re very focused on improving our coverage ratio. That came up a bit in the second quarter. It came up again with a strong performance in the third quarter, so we’re happy about that, that’s certainly one of our focus points. And we’re going to manage our balance sheet as well to make sure we have a good balance between growth and using some leverage for keeping a conservative balance sheet.
The second question you asked I think related to other assets, other bases in terms and we are very actively looking for properties really all over the U.S. Right now, our properties are limited and focused mostly on the Permian Basin and also Oklahoma and those have been two very good areas for us. But we continue to see properties and opportunities in other areas and are looking actively for new opportunities.
The third question you asked related to hydrocarbon mix and on one hand roughly 90% of the properties that are at the sponsor Lime Rock Resources are oil related. To the degree, most of the transactions that LLR Energy does coming for dropdown transactions you should expect most of those to be more oil related, because that’s just the inventory that we have. But separate from that we really don’t limit ourselves to either hydrocarbon; we try to be opportunistic in terms of looking for either gas opportunities or oil opportunities wherever we can find them. The gas opportunity today is pretty attractive at these depressed levels because it just means you are probably are going to end up paying for less of some of the other categories probable and possible. But as if and when gas prices recover, those are certainly, it creates optionality going forward. So we are looking for both hydrocarbons as we look for new deals.
And if I can slip in one follow up, on the second point with regard having an aggressive interest in other basins, is there a scale either in terms of production or dollar amount or contribution on a per unit basis that would make sense anything lower than that might not be cost effective for you, in terms of entering a new basin?
That’s a good question Michael; the way we think about it is yes you do need some critical mass to be efficient in a new basin. So while we would consider a pretty small deal as a bolt-on to an area that we already are operators in, our minimum would be let’s say $40 or $50 million or so to have a threshold size to make sure that we have critical mass in a new operating area. Don’t hold me to that per se, if we found a really attractive opportunity, we’ll consider every transaction individually but generally speaking, that’s the way we think about it, it needs to be over a 40 or 50 million for us to get all geared up in a new area.
Okay, it’s terrific. Just as a point of clarification, Tim you mentioned an IP rate for Red Lake. I assuming that was a 30 day rate?
Yes, that’s a 30 day average IP rate.
The next question comes from the line of (inaudible).
Hey guys, good morning. Just two quick questions for you. First I was wondering if you could provide an update on your plans for the term loan facility. Is that something that you could pay down early with an equity offering or potentially leave in place until maturity?
So the maturity on that is January 2017. So we obviously have lots of flexibility to leave it in place, if we wanted to, to that for out. The rate does escalate from 550 L plus 550 to L plus 700 at the end of the first quarter and then at the end of 2013, it goes up to L plus 850. So although we have lots of flexibility to leave it in place over the next few years, I think we're more than likely to refinance it during 2013.
Great and just one more question. Can you just remind us again how much of your NGL production is priced off of Bellevue versus Conway?
It's kind of a blend, depending on where our production comes from. We would tell you that our prices are more correlated to Mont Bellevue, but if you look at our price, it's kind of in between the realized prices of Mont Bellevue and Conway. Basically on our entire company weighted average, we're basically are realizing about a 9% discount to Mont Bellevue because of the fact that we have a blend between Conway and Mont Bellevue.
And there are no further questions at this time.
Okay, well thanks everybody for joining in for our third quarter conference call and appreciate all of your interest.
Thank you. This concludes today's conference call. You may now disconnect.
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