Exhibit 99.2
LRR ENERGY, L.P.
Moderator: Jaime Casas
March 6, 2014
10:00 a.m. ET
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 place on mute to prevent any background noise. After the speakers remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. To withdraw your question press the pound key.
Thank you. I will now turn 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 are 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. The forward-looking statements are based on current expectations that 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 likely 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.
Year-end 2013 production was 6,466 barrels of oil equivalent per day, which was in line with our public guidance range. Fourth-quarter production was 6522 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 nonrecurring operational and infrastructure-related issues that severely impacted production. Despite the impact of those events, we were almost able to generate a 1.0 times coverage ratio for the year.
On the acquisition front as we have 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 at 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 our equity float 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. The distribution equates to an annualized distribution of $1.96 per unit and marks our sixth consecutive quarter with a distribution increase.
With that, I will turn the call over to Charlie.
Charlie 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 about 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 year-end 2013 reserves, our estimated net proved reserves were 30.1 million barrels of oil equivalent, 88% of which were classified as proved developed and 49% were liquids. The estimated proved reserves are based on 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 6522 Boe per day, we have a production-to-proved reserve ratio program of 12.6 years.
55% of our estimated year end 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 regions. 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 who will provide more color on the operations.
Tim Miller: Thanks Charlie. For the fourth quarter, our average daily production was 6522 Boe per day. We estimate that our fourth-quarter production was curtailed by 15 to 20 Boe per day due to the severe winter weather across the areas.
Despite the weather impact, fourth-quarter production was above our internal forecast. Our operations continued to be impacted by weather in January and February this year. We currently estimate production losses for the first quarter of 2014 to be 80 to 120 Boe per day as a result of severe weather and third-party gas plant maintenance.
The partnership’s 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 and 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 toward recompletions.
In total, we intend to drill 36 wells, 19 of which are LRE-operated Red Lake wells and recomplete 32 Red Lake wells. Approximately $21.9 million or 64% of the 2014 capital will be reinvested in our Red Lake field, while 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 plan to execute 18 nonproduction-related projects, including 14 plug-and-abandonment projects and several facility upgrades. These non-production opportunities account for approximately 2% of our 2014 capital budget.
As Charlie mentioned, our lease operating expenses for the quarter were $7.3 million, which includes an approximately $600,000 of workover expenses. The $1.3 million increase compared to the third quarter was primarily due to a prior period adjustment of $425,000, increased workover activity of $300,000, year end field employee bonuses of $175,000, and frac tank rentals due to downtime problems at the Navajo refinery and expenses related to severe weather of $400,000.
I will now turn the call back to Jaime who will walk you through our year-end 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 1.34 times. For the full year of 2013, our distributable cash flow was $49.6 million, and our distribution coverage ratio was 0.97 times.
Excluding our subordinated units, our common units 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 year end. Assuming the midpoint of our 2014 production guidance as 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 $91.87 per barrel of oil and $5.06 per MMBTU of natural gas. More specific details of our hedge position are disclosed in our earnings press release.
Next, I would like to discuss our guidance for the full-year 2014. For 2014, we expect production to average between 6400 and 6600 Boe per day and LOE to average between $10.50 to $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 25% 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’s 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 had $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 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.
Operator: Again, if you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. To withdraw your question press the pound key. You first question comes from the line of Kevin Smith, Raymond James.
Kevin Smith: Would you mind discussing where we are on natural gas flaring at Red Lake? I know you are putting in or I guess the midstream operators were putting on some additional compression capacity. Is that all behind us now?
Tim Miller: Yes, it is Tim Miller. They did get their additional compression installed during the fourth quarter. We saw minor flaring in the fourth quarter; however, actually right at the moment, Frontier is having some issues with their sulphur-treating unit at the plant. We have been down about five days and expect to be down another two days. Almost. We’re going to see some significant flaring in the first quarter. That is in that number that I gave you, the 80 to 120 barrel per day curtailment due to weather and gas plant issues. So we think it is a onetime event due to maintenance on that sulphur-treating unit.
Kevin Smith: OK. And then do you foresee any other midstream constraints coming up at Red Lake during the year? Or do you think once we get past this, we will pretty much be done as far as what you can foresee?
Tim Miller: Well, — the compression is all installed, so that is not an issue anymore. They haven’t notified us of any other problems. I mean hopefully this sulphur-treating issue will be a one-time event.
Kevin Smith: OK. 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 that at some point?
Jaime Casas: Yes, Kevin, our current thought is to leave it in place. Ideally what we would like to do is leave it in place until we do a larger acquisition. And at that point, we are able to access the high-yield markets, and we would refinance the term loan with high-yield debt and term it out further out.
Kevin Smith: OK. That is all I had. Thank you.
Operator: Praneeth Satish, Wells Fargo.
Praneeth Satish: Just a couple of quick questions. On the 80 to 120 barrels of per day production that you expect will be shut-in in Q1 2014, so should I take that as
is that mostly gas, or what is the breakout of crude versus gas in that impact in Q1?
Tim Miller: Yes, it is mostly gas due to the Red Lake issue I just mentioned. I would probably say, I am guessing at this point, but about 65%, 70% gas.
Praneeth Satish: OK. Got it.
Tim Miller: And —.
Praneeth Satish: OK. And just on the Red Lake wells, the new drills there, what are the returns that you are seeing there? Is it still in the 30% to 50% range, or has anything changed there?
Tim Miller: Nothing has changed. Our results have been very consistent since 2012 — 2013 program almost generated identical returns. The 2014 plan is probably more in the 30% to 35% IRR range. It’s just a matter of the well selection is in there. We are drilling a few more St. Andres wells.
Praneeth Satish: Got it. And just last question, on the new ATM program that you have instituted, how should we think about issuance through that program? Is this going to be something that you tap on a regular quarterly basis or opportunistically?
Jaime Casas: Obviously, it will be a function of our unit price, but I would think over the course of the year we will be accessing it on a somewhat regular basis.
Praneeth Satish: OK. Great. Thank you.
Operator: Your next question comes from the line of Mike Schmitz, Ladenburg Thalmann.
Mike Schmitz: A couple of questions. First, can you just update us on what your current inventory is for both new wells and recompletions at Red Lake?
Chris Butta Yes, the current inventory, the plan for — I’m sorry, this is Chris Butta — the plan for 2014 would have 19 wells in the budget at Red Lake and 32 recompletes at Red Lake. So that is the planned for the year.
As far as the total inventory goes, we have a total net opportunity count of about 374 opportunities as a Company; the gross count is about 511. And those are basically split, I believe, about one-third, two-thirds between drilling and recompletion opportunities. So inventory-wise, if you look at the 2014 plan versus the total inventory, we have about a 7- to 8-year inventory on our development projects.
Mike Schmitz,: OK. Great. Thanks. And can you just provide some additional details on the Mid-Continent program this year given that it is 30% of the budget?
Tim Miller: In our Putnam field — there was a switch in operators in our non-operated position, and they have been very active. They started in the fourth-quarter drilling. The first two wells have come on nicely here in the first quarter. They have been impacted by weather so far so, though. That is where part of our weather impact is on those production.
But they are planning on drilling 13 horizontal Tonkawa with a couple of Cleveland wells mixed in there. So about 11 Tonkawa and two Cleveland horizontal wells in the Anadarko part of Oklahoma.
We also have two vertical wells in our East Velma acquisition. That was a drop down recently that another operator is drilling. They have drilled one already and are just now in the completion phase on it, and they are prepping to spud a second one.
Mike Schmitz: Great. Thank you. And what would be roughly the average working interest in the horizontal wells?
Tim Miller: We are roughly around 15% — 17% working interest in the horizontal wells.
Mike Schmitz: Thanks. And one last one. On the acquisition market, what are you guys seeing currently? More acquisition opportunities — gas, oil, any particular region which looked more attractive currently?
Eric Mullins: It is Eric Mullins. The market we have seen actually has been pretty active. Third quarter and fourth quarter were very busy. The first quarter usually has
a little bit of a slowdown, but we haven’t seen as much of that. We have been pretty busy and making offers and looking for transactions.
The other part of your question, in terms of regions, it has been pretty varied. 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 made offers on, and they have been quite varied. We are seeing offers up in the Oklahoma area, offers actually in some of the coalbed methane areas, opportunities up in the Rockies, opportunities in South Texas. So it has really been quite varied in terms of just the general regions where we have been looking and identifying properties that we think fit our model and making offers.
So we are pretty encouraged. We’ve got a pretty good backlog right now of transactions that we’re looking at, as well. I would say anywhere from five or six different transactions at any given time. It ebbs and flows, but right now we do have some opportunities that we are looking at that look pretty attractive and look like a good fit.
We’re not limiting ourselves to either one of the hydrocarbons. We are really much more opportunistic, and we just want to find the right property with the right profile in terms of proved, developed, producing content, as well as the decline curve and the amount of capital that the property requires given our structure. So hopefully that addresses your questions.
Mike Schmitz: That is great. Thanks. One last one — are you still targeting at least $100 million or ($50 million) to $100 million of acquisitions per year?
Eric Mullins: Yes, we are. And we’re still very confident in that. We realize that over the course of 2012 and 2013 we haven’t made that number. I think we have made about $65 million of acquisitions in 2012 and $60 million worth in 2013. But I think as we go forward and we look backwards, just in terms of average numbers, we will 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 was stated before, as those fields continue to mature and as we continue to drill up the inventory in those
areas, they become more suitable for the LRE structure. So we are still very confident in that $100 million of minimum making $100 million a year per year in acquisitions.
Having said that, transactions are lumpy. We have been doing this as a team since 2005, and over that eight-year period, it has been very consistent in that deals come in a lumpy fashion. So we’re not worried at all about where we are right now. We know we will get there. We are being very patient. To us it is very important not just to do any old acquisition. We want to do the right acquisitions to complement what we have.
The properties we have, I am sure as you have seen, with a few exceptions in terms of a few hiccups here and there, but they have 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: Great. That was a lot of good color. Thank you so much.
Operator: Your next question comes from the line of Abhi Sinha, Wunderlich Securities.
Abhi Sinha: Most of my questions have been answered. Just a quick one on trying to get my head around the strategy behind the ATM. Have you considered as some form of preparatory work to getting ready for the A&D, or is it more like making sure you have enough for distribution and CapEx and new acquisition would require separate tapping of the capital markets? How should we think about that?
Eric Mullins: It is Eric Mullins. I will respond and Jaime might have some comments, as well. But I have said it is a combination. It’s just 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 if we like the price and have a consistent selling program that doesn’t move the market and is 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 this positive. Obviously it helps our balance sheet. We
stated before that we want our debt, the cash flow to be around that 3 times over the long term, so it helps with that. And obviously, with any acquisition that we sign, we’re going to need some additional equity. And you can’t always time that exactly right.
So we just think being in the market and having this tool is a good way to complement everything we are doing.
Abhi Sinha: That’s all I have. Thank you very much.
Operator: Your next question comes from the line of John Ragozzino, RBC Capital Markets.
John Ragozzino: Just one more quick one on the ATM. Do you have a feel for what the potential capital raise is over any given year given your guys’ historical at trading volumes on average?
Jaime Casas: Yes, John. It is Jaime. We implemented the ATM program in early February, and during the month of February, we sold $2 million is what we raised. But in terms of forecasting, we really aren’t comfortable. It is dependent 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 expectation in terms of how much we might issue in the future.
John Ragozzino: OK. And just on the reserve side, can you guys reconcile the year end — this year’s 30 million barrels with the 27.8 million last year? Specifically, were there any significant price-related revisions? And can you expect to do any sort of interim redetermination on the revolver if we see continued strength in gas prices?
Chris Butta: Well, this is Chris Butta. I can talk about the reserves. We came into the year at roughly 27.9 million barrels and about 3.5 million barrels worth of acquisitions between the two drop downs, and we rolled out at the year at 30.1 million barrels.
We had a net positive increase in reserves, right at 1 million barrels just based on revisions. So I mean it was fairly positive across the board.
As far as revisions due to price, our best estimate on the reserve revisions in price is right about 2 million barrels of oil equivalent. I think a lot of that was related to natural gas prices. SEC prices went from about $2.76, I believe, year end last year to $3.67 this year. So I think that was really the big driver. Oil prices were fairly flat from an SEC perspective.
John Ragozzino: OK. And — go ahead.
Jaime Casas: I was going to talk about the revolver. Not sure if you had any follow-up questions on the reserves.
John Ragozzino: No, exactly. I was going to move on to the revolver, exactly.
Jaime Casas,: John, it is Jaime. On the revolver, we will be going through our spring redetermination in April. Probably start that process in early April, maybe late this month and conclude it in mid- to late April. And at this point we don’t even have the bank’s final price deck in terms of what they are going to use to determine our borrowing base. And so it’s very hard to predict exactly where we are going to end up on our borrowing base until we go through that process.
John Ragozzino: Fair enough. On the CapEx budget, what percentage of that if any is on the non-op side?
Tim Miller: This is Tim Miller. On the non-op side, it is about 34%. As I mentioned before, the Oklahoma program that is scheduled for 2014 is almost entirely non-op. There’s also a couple of wells in the Permian, low working interest wells in the Permian to be drilled.
John Ragozzino: And do you see any significant potential for unexpected non-op AFEs causing a, call it, mid-year revisions under your CapEx budget based on your peers’ spending patterns?
Tim Miller: I don’t see anything at this point. I think we just got a revised drilling schedule from the operator yesterday, and it was very much in line with what we had budgeted.
Charlie Adcock: John, this is Charlie Adcock. The people Tim is referring to is Lighthouse out of Oklahoma City, and they appear to be very organized, and they have mapped out their whole year. And they have been very forthcoming with all their internal information, which really, really helps us. And so I agree with Tim, I think a hiccup. It would have to be based on some event, whether it is pricing or results from wells that we drilled.
John Ragozzino: OK. Just a couple more quick ones. Can you comment on the willingness of Lime Rock Resources to potentially take any additional equity as a currency for an additional drop-down transaction, and do they have a long-term targeted equity stake that they have in mind?
Eric Mullins: 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 sell down that. We’re not in any big hurry. 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 would like to get more units out in the market and improve our float, frankly.
Right now we trade at around 125,000 units a day. That is pretty low for our space relative to our peers. And so we’d like to have a bigger float and more liquidity out there.
So no plans to do that. We certainly — again, as I said, we have the flexibility to do that, but that is really not our plan.
John Ragozzino: OK. And then last one, this is a bigger picture question, when you look at the PUD inventory and the reserve base, if we were to put ourselves in a completely non — let’s assume that there is no A&D for the next several years, whatsoever. How long do you think that the PUD inventory can sustain the current distribution?
Charlie Adcock: John, this is Charlie again, and I want to expand your question just a little bit differently in that we look at the whole opportunity set. Because we do have a tremendous amount of recompletion opportunities. And to understand that better, basically every time we drill one of the PUDs out 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 is we try to blend the two 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 60 a year. The 500 opportunities he mentioned, those are all in the proved category, and they are 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. These have been great assets out in the Permian, and we have done really, really well with them. 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 about 5%, which is a nice mover and also goes straight to the bottom line.
John Ragozzino: All right. Thanks a lot, Charlie. That is a good point and look forward to seeing you guys at the field trip.
Operator: Your next question comes from the line of Michael Gaiden, Robert W. Baird.
Michael Gaiden: I appreciate the color on first-quarter production. Can you at all share with us how LOE is trending in the first quarter, as well?
Tim Miller: It is really early to tell in the first quarter, but I will say this about the frac tanks that we had — we moved very aggressively in the 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 a couple of weeks, and we moved in very aggressively and brought in outside storage tanks, frac tanks so we could continue to produce.
And then we had to transfer all that fluid back out through our facilities. All those tanks have been released. So that cost will be much lower in the first quarter.
Other than that, it’s very hard to anticipate. Also, we had the year-end field bonuses paid in the fourth quarter. That is not an issue in the first quarter. I mean operating costs are going to trend lower in the first quarter compared to fourth quarter.
Charlie Adcock: It is Charlie again. I’d just add one comment to that. As we do move more and more towards a liquids-weighted product stream, it is LOE cost on a dollar basis or higher than you have for gas. For instance, our Potato Hills field, which is all gas, we run about $0.30 per Mcf on that, whereas out in Red Lake, we are more in the $15 to $16 per barrel range. But you also with that added — with that increased LOE, we have much, much better margins. When you think about a $15 or $16 cost structure against a $90 or $100 oil price, your margins are much more substantial.
Michael Gaiden: Charlie, thank you for that color. And Jaime, can I please ask what kind of seasonality should we expect in SG&A for the year on that?
Jaime Casas: Seasonality 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 or the third. But you are looking at no more than $400,000 to $500,000 difference in terms of the middle quarters being lower than the year end and beginning quarter.
Michael Gaiden: Great. Thank you. And can I also ask for some 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 is a noncash item, and it does not impact our distributable cash flow. As was mentioned earlier, the impairment was related to some of our Permian assets and our Gulf Coast assets. There were several factors that cause the impairment. But really the main drivers were really — there were several, and individually they just added up.
Going forward, the lower forward oil curve impacted the valuations on the assets. We did have somewhat higher forecasted operating costs on a go forward basis for both areas.
Really a big driver for both areas was the lower realized NGL prices that we saw in 2013 and was forecasted forward. We hope to see improvement there, but that was a big driver.
And then finally, there were some reserved category re-classifications and then just some slight performance-related items. So no one item in particular, but when you have several of those kind of items go in the same direction, I mean I think those are really the big drivers on the impairment.
Michael Gaiden: Great. Thanks, Chris. And then can I ask 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 do it for me. Thanks.
Jaime Casas: Mike, it is 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 us to be right around that goal.
And then in terms of distribution coverage, we don’t provide guidance in any kind of forecast on distribution coverage.
Eric Mullins: It is Eric Mullins. I will just add to that. We have said this before, but our goal is to get to at least a 1.2 times coverage. We have stated that acquisitions and accretive deals are how we going to do that. So that is still very consistent with what our expectations are. We like to have our coverage much higher than it is right now right around that 1 times level, and we’re committed to doing that.
Michael Gaiden: Thanks, Eric. Is this a near-term goal? Is this achievable in 2014 or 2015, or is this something that is likely going to be 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 are one of the smallest of our peer group at just over a $400 million market cap. So it wouldn’t take a huge transaction to really make a big difference for us. And I think over the course of last year, including recently we have looked at transactions that would have had a meaningful impact on
that front, as well. So we’re confident that we will have an opportunity to find the right deal that is accretive and improves our coverage.
Michael Gaiden: Thanks, Eric. That is it for me.
Operator: Your final question comes from the line of Jon Jung, Trailhead Asset Management.
Jon Jung: Good morning. Wonder if you could give us any further information about the initial production coming out of the new wells in Oklahoma, the horizontals.
Tim Miller: Yes, this is Tim Miller. There have been two wells completed to date — it’s very early — they came 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. Obviously they make associated gas with those I think in the neighborhood, each one makes in the neighborhood of about 1 million per day of associated gas. So we are very — it is going to be very interesting to see just how they perform over the next few months.
Jon Jung: And what do those cost to complete? What are you looking at for IRR-wise on that?
Tim Miller: The IRRs, again, — we’ve got them forecast for this year’s budget, all 13 of them combined at about a 30% IRR.
Jon Jung: OK. And what do they cost —
Tim Miller: We will see, but on average, these first two are slightly above our expectations.
Jon Jung: OK. What did it cost you to drill and complete them?
Tim Miller: They are about $4.2 million gross each. And, again, we have an average of 17% working interest in them.
Jon Jung: Terrific. Thank you very much.
Tim Miller: ($4.2) million to $4.5 million.
Jon Jung: Thanks for the information.
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 fourth-quarter 2013 earnings conference call. You may now disconnect.
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