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LRR Energy LP (NYSE:LRE)

Q4 2013 Earnings Conference Call

March 06, 2014 10:00 AM ET

Executives

Jaime Casas – Vice President, Chief Financial Officer and Secretary

Eric Mullins – Co-Chief Executive Officer and Chairman

Charlie Adcock – Co-Chief Executive Officer and Director

Tim Miller – Vice President and Chief Operating Officer

Chris Butta – Vice President and Chief Engineer

Analysts

Kevin Smith – Raymond James & Associates

Praneeth Satish – Wells Fargo Securities, LLC

Mike Schmitz – Ladenburg Thalmann

Abhishek Sinha – Wunderlich Securities

John Joseph Ragozzino – RBC Capital Markets

Michael Gaiden – Robert W. Baird

John Jung – Trailhead Asset. Management

Operator

Ladies and gentlemen, thank you for standing by. And welcome to the LRR Energy Fourth Quarter 2013 Earnings 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.

I would now turn the conference over to Mr. Jaime Casas. Please go ahead, sir.

Jaime Casas

Thanks, operator and good morning everyone. Welcome to LRR Energy’s fourth quarter and full year 2013 earnings conference call. Also presenting this morning, our Co-Chief Executive Officers, Eric Mullins and Charlie Adcock; and our Chief Operating Officer, Tim Miller. Chris Butta, our Chief Engineer is also with us and available for questions.

During the course of the call management will make forward-looking statements about LRE. 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 statements. Forward-looking statements involve certain risks and uncertainties and may not prove to be accurate. These risks and uncertainties are included in the Risk Factors section of our 2013 Form 10-K which we expect to file next week with the Securities and Exchange Commission.

Additionally, during the course of today’s discussion management will refer to adjusted EBITDA, distributable cash flow and distribution coverage ratio 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 yesterday.

I will now turn the call over to Eric.

Eric Mullins

Thanks, Jaime and good morning everybody. We appreciate you joining us for our earnings call this morning. In a few minutes, Charlie, Tim and Jaime will discuss our results in detail. But in summary, we are pleased with our operating and financial results.

Yearend 2013 production was 6,466 barrel of oil equivalents per day which was in line with our public guidance range. Fourth quarter production was 6,522 barrel of oil equivalents per day which was above our internal forecast for the quarter. Adjusted EBITDA was $20.4 million for the quarter, and $79.6 million for the year. For the quarter, distributable cash flow was $12.9 million and our total unit distribution coverage ratio was 1.0 times. For the year, distributable cash flow was $49.6 million and our total unit distribution coverage ratio was 0.97 times.

During 2013, and primarily during the first quarter we faced a few non-recurring operational and infrastructure-related issues that severely impacted production. Despite that – despite the impact of those events, we’re almost able to generate 1.0 times coverage ratio for the year. On the acquisition front, and as was stated in the past, LRE is committed to a disciplined and patient approach of acquiring assets that we believe are well suited for the MLP structure and that prices that provide long-term distributable cash flow per unit accretion. While we can’t predict the timing of our next transaction, the A&D market for suitable assets continues to be very active, and LRE is encouraged by the current backlog of potential transactions.

Turning to a couple of recent developments, we entered into a $75 million At-the-Market or ATM offering program in February. We believe that this program will allow us to incrementally add to an equity flow and overall balance sheet in an efficient and consistent manner. On February 14, LRE paid a cash distribution of $0.49 per unit for the fourth quarter of 2013. Distribution equates to an annualized distribution of $1.96 per unit and marks us sixth consecutive quarter with a distribution increase.

With that, I will turn the call over to Charlie.

Charles Adcock

Thanks, Eric. I’d like to start by reviewing our operating results for the fourth quarter. Yesterday, we reported total net production of 600,000 Boe for the quarter. Our production was 49% natural gas, 37% oil and 14% natural gas liquids for the fourth quarter. As a result, of our continued liquids-focused development activity during the year, we increased our fourth quarter liquids production mix to 51% from 46% during the fourth quarter of 2012.

Lease operating and workover expenses for the quarter were $7.3 million or $12.21 per Boe, compared with $6 million or $9.87 per Boe in the third quarter. Tim will explain the reasons for the increase in a moment. For the year, our lease operating and workover expenses were $25.4 million or $10.76 per Boe, which was just above our 2013 guidance range of $10.25 to $10.75 per Boe. Production and ad valorem taxes for the fourth quarter were $2.1 million or $3.56 per Boe and represented 7.1% of gross revenue. This is compared to the production and ad valorem taxes for the third quarter of $2.4 million or $4 per Boe.

Now, turning to our yearend 2013 reserves. Our estimated net proved reserves were 30.1 barrels of oil equivalent, 88% of which were classified as proved developed and 49% were liquids. The estimated proved reserves are based on a fully engineered independent reports prepared by our third-party reserve engineers Miller and Lents and Netherland, Sewell and Associates. Based on fourth quarter average daily production of 6,522 Boe per day, we have a production to proved reserve ratio of 12.6 years. 55% of our estimated yearend proved reserves are located in the Permian Basin, 35% in the Mid-Continent and the remaining 10% in the Gulf Coast area. The standardized measure of these reserves was $392.6 million, based on SEC pricing of $96.78 per barrel of oil and $3.67 per MMBtu of natural gas.

During the quarter, we recorded an impairment of $63.7 million on our proved properties in the Permian Basin and Gulf Coast region. This impairment was primarily due to lower estimated future net realizable liquids prices and reserve category reclassifications. The impairment has no impact on our cash flows, liquidity position or debt covenants.

I will now hand the call over to Tim Miller, who will provide more color on the operations.

Tim Miller

Thanks, Charlie. For the fourth quarter, our average daily production was 6,522 Boe per day. We estimated our fourth quarter production was curtailed by 15 Boe to 20 Boe per day due to the severe winter weather across the reef areas. Despite the weather impact, fourth quarter production was above our internal forecast. Our operations continue to be impacted by weather in January and February this year, we currently estimate production losses for the first quarter of 2014 to be 8,222 Boe per day, as a result of severe weather and third-party gas plant maintenance.

At partnership quarter to-date average net production through February 28, 2014 was approximately 6,400 Boe per day. During the three months ended December 31, 2013, our total cash capital expenditures totaled $10.9 million. Most of the capital was invested in our Red Lake field where we successfully drilled and completed three wells, recompleted seven wells during the quarter. For the year, we completed 26 wells and recompleted 28 wells at our Red Lake field.

Turning to our 2014 plans, our Board of Directors approved a $34 million capital budget for 2014, approximately $27 million or 79% of the budget is allocated towards drilling, and roughly $6.5 million or 19% of the total is dedicated towards recompletions. In total, we intent to drill 36 wells, 19 of which are LRE operated Red Lake wells and recompleted 32 Red Lake wells. Approximately, $21.9 million or 64% of the 2014 capital will be reinvested in our Red Lake field. Approximately 70% of the budget is in the Permian and the remaining 30% is in the Mid-Continent primarily for non-operated horizontal drilling in the Putnam field.

During 2014, we planned to execute 18 non-production related projects, including 14 plugging and abandonment projects and several facility upgrades. These non-production opportunities account for approximately 2% of our 2014 capital budget.

As Charlie mentioned, our leased operating expenses for the quarter were $7.3 million which included approximately $600,000 of workover expenses. The $1.3 million increase compared to the third quarter was primarily due to the prior period adjustment of $425,000 increased workover activity of $300,000, yearend field employee bonuses of $175,000 and frac tank rentals due to downtime problems at the Navajo Refinery and expense related to the severe weather of $400,000.

I will now turn the call back to Jaime, who will walk you through our yearend financial results and guidance.

Jaime Casas

Thanks, Tim. Adjusted EBITDA was $20.4 million and $79.6 million for the quarter and full year 2013 respectively. For the quarter, our distributable cash flow was $12.9 million and our distribution coverage ratio was 1.0 times. Excluding our subordinated units, our common unit distribution coverage was approximately 1.34 times, for the full year 2013 our distributable cash flow was $49.6 million, and our distribution coverage ratio was 0.97 times. Excluding our subordinated units, our common unit distribution coverage ratio was 1.31 times.

Next, I would like to provide an update on our current commodity hedge position, which reflects additional 2014 NGL swaps we entered into subsequent to yearend. Assuming the midpoint of our 2014 production guidance is held flat through 2017, our current estimated total production is 83% hedged in 2014, 69% in 2015, 55% in 2016 and 44% in 2017. Weighted average prices during the period are $92.87 per barrel of oil and $5.06 per MMBtu of natural gas. More specific details of our hedge position are disclosed in the earnings press release.

Next I’d like to discuss our full – our guidance for the full year 2014. For 2014, we expect production to average between 6,400 Boe per day and 6,600 Boe per day and LOE to average between $10.50 and $11 per Boe. As Tim mentioned, we expect total capital expenditures to be $34 million for the full year 2014, $20 million of which we estimate to be maintenance capital. Our maintenance capital estimate is based on 24% of 2013 adjusted EBITDA.

As Tim mentioned, abnormally harsh winter conditions have impacted production for us and other producers in the area over the past few months. Notwithstanding the weather has impact on our production, our estimated quarter to-date average net production through February 28 was approximately 6,400 Boe per day. I would like to close with our balance sheet. As of today, we have $205 million of outstanding borrowings under our revolving credit facility and $50 million of outstanding borrowings under our term loan facility.

Our current liquidity position is approximately $50 million consisting of $45 million borrowings of available borrowing capacity under our revolving credit facility and approximately $5 million of available cash on hand.

Operator, you can now open the call for questions.

Question-and-Answer Session

Operator

Thank you (Operator Instructions) I’ll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Kevin Smith with Raymond James.

Kevin Smith – Raymond James & Associates

Would you mind discussing where we are on natural gas planning at Red Lake I know you’re putting in or I guess the midstream operators will put on some additional – compressing capacity? Is that all behind it now?

Tim Miller

Yes this is Tim Miller. They didn’t get their additional compression installed during the fourth quarter, we saw minor flaring in the fourth quarter. However, it actually at the moment frontier is having some issues with their sulfur treating unit that plant we’ve been down about five days and expecting down another two days almost we’re going to see some significant playing in the first quarter that is in that number that I gave you the 80 barrel per day to 120 barrel per day curtailment due to weather and cash plan issues. So, we think it’s one-time event due to this maintenance on that sulfur treating units.

Kevin Smith – Raymond James & Associates

Okay. And then, do you foresee any other midstream constraints coming up that Red Lake during the year, or do you think once we get past this will pretty much be done as far as what you can foresee?

Tim Miller

No, they’re not having – the compression is all installed so that’s not issuing anymore. But they have notified this as many other problems I mean, hopefully this sulfur treating issue is a one-time event.

Kevin Smith – Raymond James & Associates

Okay, great. And Jaime, can I get your thoughts on the term loan facility, what are you thinking now as far as how long you want to have that in place and thoughts about potentially refinancing at some point?

Jaime Casas

Yeah, [indiscernible] I think our current inventory in place ideally what we’d like to do is leave it in place until we do a larger acquisition and at that point, we’re able to access the high yield markets and we would refinance the term loan with high yield that’s and kind of coming out further out.

Kevin Smith – Raymond James & Associates

Okay, that’s I’ll have. Thank you.

Operator

Your next question comes from the line of Praneeth Satish with Wells Fargo.

Praneeth Satish – Wells Fargo Securities, LLC

Hi, good morning just couple of quick questions. I guess just on the 80 barrels of per day production to 120 barrels of per day production that you expect will be shown in Q1 2014, so should I take that as, is that mostly gas or what’s the break-out of crude versus gas and that impact in Q1?

Tim Miller

Yeah, I think it’s mostly gas due to that these Red Lake – the Red Lake issue I just mentioned I would probably say I’m guessing it at this point for about 65% to 70% gas.

Praneeth Satish – Wells Fargo Securities, LLC

Okay, got it.

Tim Miller

[Indiscernible].

Praneeth Satish – Wells Fargo Securities, LLC

Okay. And just on the Red Lake wells that the new drills there, what are the returns that you’re seeing there is it still in the 30% to 50% range or has anything changed there?

Tim Miller

Nothing is changed our results have been very consistent from 2012 or 2013 program almost generated identical returns. The 2014 plan is probably more in the 30% to 35% IRR range. It is a matter of that the well selection as we drill a few more shallow wells as well as same in this type wells.

Praneeth Satish – Wells Fargo Securities, LLC

Got it. And just last question on the new ATM program that you’ve instituted, how should we think about issuance through that program which is going to be something that you tap on the regular quarterly basis or opportunistically?

Tim Miller

Obviously the function of our unit price, but I would think over the course of the year will be accessing on our somewhat regular basis.

Praneeth Satish – Wells Fargo Securities, LLC

Okay, great. Thank you.

Operator

Your next question comes from the line of Mike Schmitz with Ladenburg.

Mike Schmitz – Ladenburg Thalmann

Couple of questions. First, can you just say about your current inventory is for both new wells and recompletions of Red Lake?

Chris Butta

Yeah. For the current inventory the plan for sorry this is Chris Butta. The plan for 2014 we have 19 wells in the budget at Red Lake and 33 recompletes Red Lake so that’s the plan for the year. As far as the total inventory goes, we have a total net opportunity count of about 374 opportunities as a company that gross counted about 511. And, those are basically split up I believe about one-third, two-third between drilling and recompletion opportunities. So, inventory-wide if you look at the 2014 plan versus the total inventory we have about 7 year to 8 year inventory on our development projects.

Mike Schmitz – Ladenburg Thalmann

Great, thanks. And can you just provide some additional details about on the Mid-Continent program this year given that as 30% of the budget?

Tim Miller

Yes, this is Tim Miller. The majority of that Mid-Continent program is located in our Putnam field, it’s a non-operator out there that, there was a switching operator in our non-operator position now it’s been very active they started in the fourth quarter drilling the first two reserve two wells come on nicely here in the first quarter. They have been impacted by weather so far, though that’s were part of our weather impact is on those production, but they’re plan on drilling 13 horizontal wells Tonkawa that with a couple of Cleveland wells mixed in there. So about 11 Tonkawa, Cleveland horizontal wells in the Anadarko part of Oklahoma. We also have two vertical wells are at East Velma acquisition that was dropped down recently that another operator is drilling and they’ve drilled one already and just down in the completion phase on it and they’re prepared for the second one.

Mike Schmitz – Ladenburg Thalmann

Okay. And what would be the roughly the working interest in the horizontal wells?

Tim Miller

We’re roughly around 15% – 17% working interest in the horizontal wells.

Mike Schmitz – Ladenburg Thalmann

Thanks. And one last one, on the acquisition market, what do you guys seeing currently more acquisition opportunities gas, oil or any particular region which looked more attractive currently?

Eric Mullins

Yes Mike it’s Eric Mullins. The market we’ve seen actually has been pretty active third quarter and fourth quarter was very busy. The first quarter was usually a little bit of a slowdown though we haven’t seen as much of that, we’ve been pretty busy and making offers and looking. The other part of your question in terms of regions has been pretty varying. We continue to see opportunities in the Permian, which obviously has been very active.

But we also have seen a mixture of both hydrocarbons oil and gas opportunities that we have – that we’ve made offers on. And that have been varying, we’ve seen offers in the Oklahoma area, offers actually in some of the Corbin and [indiscernible] areas, opportunities up in the Rockies, opportunities in South Texas so it’s really been quite varying in terms of just the general regions where we’ve been looking and identifying properties that we think fit our model and making offers.

So we’re pretty encouraged we got a detailed – a pretty good backlog right now of transactions that we’re looking at as well, I would say, anywhere from 5 or 6 different transactions at any given time it ebbs and flows but right now we do have some opportunities that we’re looking at that look pretty attractive and look like a good fit. We’re not limiting ourselves to either one of the hydrocarbons we’re really much more opportunistic and we just want to find the right property with the right profile in terms of true developed producing content as well as the decline curve and the amount of capital that property requires given our structure.

So hopefully that addresses your questions.

Mike Schmitz – Ladenburg Thalmann

Well that’s great thanks. One more I was wondering one, are you still targeting a lease of [indiscernible] of acquisitions per year?

Eric Mullins

Yes, we are. And we’re still very confident in that, we realized that over the course of 2012 and 2013, we haven’t made that number, I think, we made about $65 million of acquisitions in 2012 and $60 million worth in 2013. And I think as we go forward and we look backward just in terms of average numbers we’ll hit our targets and we’re still very confident in that. I think as you know our sponsor Lime Rock Resources has been a very, very active driller in many of our fields. And as those as was stated before, as those fields continue to mature and as we continue to drill up the inventory in those areas, and they’ve become a more suitable for the LRE structure. So we’re still very confident in that $100 million a minimum making $100 million a year per year, tuck-in acquisition.

Having said that, transactions are lumpy, we’ve been doing this as a team since 2005 and over that eight year period it’s been very consistent and that deals come in a lumpy fashion if you will. So we’re not worried at all about kind of where we are right now, we know we’ll get there, we’re being very patient. To us it’s very important not just to do linear the acquisition, we really wanted to do the buy the acquisitions and compliment what we have. The properties we have of course you’ve seen with the few exceptions in terms of few hiccups here and then but they really performed very well and very consistently. And so we are being very careful about what we want to add to this portfolio of assets as we go forward.

Mike Schmitz – Ladenburg Thalmann

Right, that’s all a lot of good color. Thank you so much.

Eric Mullins

Sure.

Operator

Your next questions comes from the line of Abi Sinha with Wunderlich Securities.

Abhishek Sinha – Wunderlich Securities

Good morning, everybody. Most of my questions have been answered. Just a quick one on trying to get ahead on the strategy behind the ATM I mean, can you consider as it like some form of preparatory work to getting ready for the A&D, or is it more like making sure you have enough for distribution CapEx and new acquisition would require the separate tapping of the capital markets? How should we think about that?

Eric Mullins

Yes Abi it’s Eric Mullins, I’ll respond and Jaime might add some comments as well. But I’d say it’s a combination, I think it’s a very efficient way to issue equity. I think you know our float is relatively low. We do anticipate making acquisitions as we go forward we never know exactly when those are going to come up. So, like the price and having consistent our selling program that doesn’t move the market and is a very methodical to us is very efficient and a good tool to use.

In addition to that, obviously so the benefit of getting additional units out in the market we think is positive, obviously helps our balance sheet was stated before that with our debt, the cash flow would be around that 3 times over the long-term, so it helps with that and obviously with an acquisition that we signed we’re going to need some additional equities. So in general, we timed that exactly right. So we’re just being in the market and having this tool as a good way to complement everything we’re doing.

Abhishek Sinha – Wunderlich Securities

Sure, that’s all I have. Thank you very much Eric.

Eric Mullins

Sure.

Operator

Your next question comes from line of John Ragozzino with RBC Capital Markets.

John Joseph Ragozzino – RBC Capital Markets

Hi, good morning guys.

Jaime Casas

Good morning, John.

John Joseph Ragozzino – RBC Capital Markets

Just one more quick one on the ATM. You have a feel for what potential capital raised is, over a given year, given your guidance historical of trading volumes, on average?

Jaime Casas

Yes, John it’s Jaime. We implemented the ATM program in early February and during the month of February we sold like $2 million is what we raised, but in terms of forecast and we were really uncomfortable it’s depended on so many things. One is, how successful we are in the acquisition market, obviously our unit price and so I don’t want to give any kind of forecast or expectations in terms of how much we might issue in the future.

John Joseph Ragozzino – RBC Capital Markets

Okay. And just one on the reserve side, can you guys reconcile the yearend, this year’s $30 million barrels with the $27.8 million barrels last year specifically were there any significant price related revisions and can you expect to do any sort of in term of a redetermination on the revolver as we continue to strengthen the gas prices?

Chris Butta

Well this Chris Butta. And to talk about the reserves I mean, we came into the year at $27 point – roughly $27.9 million barrels at about $3.5 million barrels worth of acquisitions between the two dropdowns, and we rolled out the year at $30.1 million barrels. We had a net positive increase in reserves of [indiscernible] barrels just based on revisions. So, I mean it was very positive across the Board. As far as revision due to price, our best estimate on the reserve revision due to price is right about 2 million barrels of oil equivalent. We did and I think a lot of that was related to natural gas prices, the SEC prices went about [indiscernible] I believe during last year to 367 this year and I think that was a big driver oil prices were fairly flat on an SEC’s perspective.

John Joseph Ragozzino – RBC Capital Markets

Okay and can go ahead.

Jaime Casas

I was talking about the revolver, attributing follow-up on the reserves.

John Joseph Ragozzino – RBC Capital Markets

No, thanks Jaime, I was going to move on to the revolver exactly.

Jaime Casas

Yes, so it’s Jaime. On the revolver we’ll be going through our stringent determination in April probably set that process in early April and may be late this month and kind of put this in mid-to-late April. And so, I don’t even know if – at this moment we didn’t have the bank’s final price tag in terms of what they’re going to have to determine our borrowing base. And so, it’s very hard to predict exactly where we’re going to end up on our borrowing base once we get – until we get to that process.

John Joseph Ragozzino – RBC Capital Markets

Fair enough. On the CapEx budget, what percentage of that if any is on the non-op side?

Tim Miller

Yes, this is Tim Miller. On the non-op side it’s about 34% non-op as I mentioned before, those at Oklahoma program scheduled for 2014 is almost entirely non-op and, there is a couple of – also couple of wells in the Permian low-interest, working interest wells in the Permian to be drilled.

John Joseph Ragozzino – RBC Capital Markets

And in this year, significant potential for unexpected non-op ASC is causing a midyear revision of your CapEx budget based on your peers spending plans?

Tim Miller

I don’t see as any at this point that we just got to revise the schedule – the drilling schedule from we operated yesterday and it was very much in line with what we had budgeted.

Charlie Adcock

Yes John this is Charlie Adcock. The people Tim is referring to [indiscernible] of Oklahoma City, and they appeared to be very organized and they’ve mapped up their whole year and they’ve been very forthcoming with all their internal information would really, really helps us. And so I can’t agree with Tim I think a hiccup and we’d have to be based on some event whether it’s pricing or results from wells that we drilled.

John Joseph Ragozzino – RBC Capital Markets

Okay, and just a couple of more quick ones. Can you comment on the willingness of Lime Rock Resources potentially take any additional equity as a currency for additional dropdown transaction and today have it long-term targeted equity stake that they have in mind?

Charlie Adcock

Well, just in terms of where we are right now I think you probably know we own about 33% of the total outstanding units at Lime Rock Resources I think over time as was stated we will fell down that without any decree, we plan to do it in a methodical way. That is certainly an option to take units back, but we don’t have any plans to do that, our plan would be, we’d like to get more units out in the market and improve our flow frankly. Right now, we trade around 125,000 units a day and that’s pretty low for our space relative to our peers and so we’d like to have a better flow and more liquidity out there. So, no plans to do that we certainly again as I said, we have a flexibility to do that, but that’s really not our plan.

John Joseph Ragozzino – RBC Capital Markets

Okay. And then, last one just kind of a bigger picture question. When you look at the pud inventory on the reserve base we were to finish off in a complete non – let’s assume that there is no way indeed for the next several years whatsoever how long do you think that pud inventory can sustain the current distribution?

Charlie Adcock

Yeah, John this is Charlie again. And I want to explain your question just a little bit differently in that we look at the whole opportunities because we do have a tremendous amount of recompletion opportunities and to understand that better basically every time we drill one of the puds in Red Lake or in the Permian we usually end up with anywhere from one to two or three behind pipe opportunities and those tend to have higher IRRs associated with them. And so what we try to do this we try to plan that to and get a good mix of puds each year as well as recompletions to maximize our production at the least amount of CapEx. So with that in mind as Chris mentioned we have over 500 opportunities, we’re doing about 68 a year. These, the 500 opportunities he mentioned those are all in the proved category.

And they’re signed off by our third-party engineers that doesn’t mean that we won’t see other opportunities outside of those as well. So, we’re very fortunate that it’s – these have been great assets out in the Permian and we’ve done really, really well with them and as you can see from as I mentioned in my part of the talk from the fourth quarter of 2012 to the fourth quarter of 2013 we increased our liquids ratio by 5% which is a nice move and also our goal straight to the bottom line.

John Joseph Ragozzino – RBC Capital Markets

All right, thanks a lot Charlie it’s a good point. And look forward to seeing you guys at the future.

Charlie Adcock

Good.

Tim Miller

Thanks John.

Charlie Adcock

Thanks John.

Operator

Your next question comes from the line of Michael Gaiden with Robert W. Baird.

Michael Gaiden – Robert W. Baird

Good morning, thanks for taking my call. I appreciate the color on first quarter production, could you also share with us LOE’s pending in the first quarter as well?

Tim Miller

Yeah, it’s really early to tell in the first quarter, but I will say this about the frac tank that we had we moved very aggressively in this fourth quarter when we saw the weather coming in and also when Navajo started having issues with their refinery in terms of handling waste disposal. They were curtailed there couple of weeks and we moved in very aggressively and brought in an outside storage tank, frac tanks as to produce two and then we had to transfer all that and put it back out through our facilities all those tanks have been released. So that costs will be much lower in the first quarter. Other than that is very hard to anticipate some of the other obviously we had the yearend field bonuses that paid in the fourth quarter that’s not an issue in the first quarter. So, I mean, the operating costs are going to trend lower in the first quarter compared to the fourth quarter.

Charlie Adcock

This is Charlie. Again I’d just add one comment to that. As we do move more and more towards the liquids weighted product stream, it is LOE cost on a dollar basis are higher than you have for a gas. For instance, Potato Hills field which is all gas, we run about $0.30 per Mcfe on that whereas I mean, in Red Lake we’re more in the kind of $15, $16 per barrel range, but you also with that added – with that increased LOE we had much, much better margins and we think about our $15 or $16 cost structure against $1900 [ph] oil price your margins are much more substantial.

Michael Gaiden – Robert W. Baird

Charlie, thank you for that color. And I need to – I please ask what kind of seasonality should we expect in SG&A in the year ahead?

Charlie Adcock

Seasonality in on the G&A side, again you should definitely expect the fourth quarter and the first quarter of each year to be higher than the second quarter and the third. But you’re looking at no more than $400,000 to $500,000 difference in terms of the middle – middle quarters seem lower than the yearend and the beginning quarter.

Michael Gaiden – Robert W. Baird

Great, thank you. And can I ask you to express a more color on the write-down in the fourth quarter?

Chris Butta

Yes, this is Chris Butta. Regarding the impairment, I mean just as a reminder, the impairment in the non-cash item I mean it does not impact our distributable cash flow. As we mentioned earlier, impairment was related to some of our Permian assets and our Gulf Coast assets. There were several factors that caused the impairment, really the main drivers were really there were several and just individually they just added up going forward the lowering forward oil curve impacted valuations on the assets, we did have somewhat higher forecasted operating costs on a go-forward basis through both areas.

Really a big driver for both areas was the lower realized NGL prices that we saw on 2013 and was forecasted really going forward we hope to see improvement there but that was the big driver. And then finally, there were some reserve category reclassifications and then just some performance – some site performance items. So, no one-item in particular, but when you have several of those kind of go in the same direction I mean that those are really the big drivers on the impairment.

Michael Gaiden – Robert W. Baird

Great, thanks Chris. And then lastly Jaime or anybody else on the team, what are your goals as far as exiting the year of 2014 in terms of leverage and DCF coverage that will be performing [ph]? Thanks

Jaime Casas

Yes Mike its Jaime, and in terms of leverage our stated goal is just to stay under 3 times. I think we’re slightly above that today and so I would expect it to be right around that kind of goal. And then in terms of distribution coverage we don’t provide guidance andg any kind of forecast on distribution coverage.

Eric Mullins

Mike it’s Eric Mullins. I’ll just add to that. We’ve said this before, but our goal is to get to at least to 122 times coverage. We stated that acquisitions and creative deals are how we’re doing to do that. So that’s still very consistent with what our expectations are. We like to have a coverage much higher than it is right now right around that one times level. And we’re committed to doing that.

Michael Gaiden – Robert W. Baird

Thanks, Eric. Is this a near-term goal, or is this achievable in 2014 or 2015, or is this something that is likely going to become several years to get there?

Eric Mullins

No I think we would be disappointed if it took several years. I think given our size we’re one of the smallest of our peer group at just over $400 million market cap. It wouldn’t take a huge transaction to really make a big difference for us. And think with over the course of last year, including recently if you looked at transactions that would have had a meaningful impact on that front as well. So, we’re confident that we’ll have an opportunity to find the right deal that is accretive and pulls our coverage.

Michael Gaiden – Robert W. Baird

Thanks, Eric. That’s it from me.

Eric Mullins

Sure.

Operator

Your final question comes from the line of John Jung with Trailhead Asset. Management.

John Jung – Trailhead Asset. Management

Good morning.

Jaime Casas

Good morning.

Eric Mullins

Good morning.

John Jung – Trailhead Asset. Management

I wondered if you could give us any further information about the initial production coming out of the new wells in Oklahoma horizontals?

Tim Miller

Yes this is Tim Miller. There has been two wells completed to date, one is producing over four – it’s very early that come on in January. One is producing over 400 barrels of oil per day, initially and the other is around 300 barrels of oil per day initially. Honestly we’ll make associate gas with those I think, in the neighborhood. Each one making the neighborhood about 1 million per day of associated gas. So we’re very – it’s going to be very interesting to see just how they perform over the next few months.

John Jung – Trailhead Asset. Management

And whether wells cross to complete, what do you look that for IRRs on there?

Tim Miller

The IRRs, again we’re – again these are line at – we’ve got in forecast for this year’s budget of 13 of them combined at about 30% IRR.

John Jung – Trailhead Asset. Management

Okay and what…

Tim Miller

I will say on an average these first two are slightly above our expectations.

John Jung – Trailhead Asset. Management

Okay. And what are the gross that you to drill and complete them?

Tim Miller

There are about $4.2 million gross each. And again we have a 17% working on average 17% working interest in them.

John Jung – Trailhead Asset. Management

Terrific. Thank you very much.

Tim Miller

$4.2 million, $4.5 million.

John Jung – Trailhead Asset. Management

Thanks. Thanks for the information.

Tim Miller

Okay.

Operator

There are no further questions.

Eric Mullins

All right this is Eric Mullins. We appreciate everybody joining us this morning. Don’t hesitate to call us if you have any other follow-up questions. Thanks very much.

Operator

Thank you, ladies and gentlemen. This concludes today’s LRR Energy’s fourth quarter 2013 earnings conference call. You may now disconnect.

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