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Executives

James Daniel Westcott – EVP and CFO

Cary Brown – Chairman, President and CEO

Paul Horne – EVP and COO

Micah Foster – Chief Accounting Officer and Controller

Kyle McGraw – EVP and Chief Development Officer

Analysts

Daniel Guffey – Stifel Nicolaus

Kevin Smith – Raymond James

John Ragozzino – RBC Capital Markets

Praneeth Satish – Wells Fargo

Abhishek Sinha – Wunderlich Securities

Legacy Reserves LP (LGCY) Q4 2013 Earnings Conference Call February 20, 2014 10:00 AM ET

Operator

Welcome to the Fourth Quarter and Annual 2013 Conference Call for Legacy Reserves LP. At this time, all participants are in a listen-only mode. Following the call, there will be a question-and-answer session. As a reminder, this call is being recorded today, February 20, 2014.

I will now turn the conference over to Dan Westcott, Legacy’s Chief Financial Officer.

James Daniel Westcott

Thank you. Good morning everybody. I appreciate everybody dialing in to Legacy’s Q4 and annual 2013 earnings call. Before we begin, I would like to remind you that during the course of the call, Legacy management will make certain statements concerning the future performance of Legacy and other statements that will be forward-looking as defined by securities laws. These statements reflect our current views of future events and are subject to various risks, uncertainties and assumptions. Actual results may differ materially from those discussed. Please refer to Legacy’s 10-K which we hope to file tomorrow, February 21, and subsequent reports that’s filed with the Securities and Exchange Commission for additional disclosure.

Before we get started on the call, I just want to mention housekeeping note. In addition to our earnings release last night, we issued a press release letting everyone know that our 2013 tax prep is complete. K-1’s are available on Deloitte’s partner linked data site which can be accessed through our website which is www.legacylp.com, and look for the tax information header at the top of the screen. I appreciate the team for getting that quickly, that was a record speed for us this year and we’re happy to have that done.

So as I look at the comments for the day, talking about the agenda for a minute, we’ll start with Cary Brown, our Chairman, President and CEO. He’ll provide commentary on the quarter and the year. And then I’ll discuss highlights of our financials and walk through our new 2014 guidance. I will then open up the call for Q&A, and we’re fortunate to have the entire management team here in Midland this morning. So we’ll do our best to address your questions with the right person. Cary, can you kick start?

Cary Brown

Sure Dan, thanks. Thanks again for our friends and unitholders for joining us today. I’m encouraged to be here. After a record year of acquisitions in 2012, Legacy focused on integration and execution in 2013. We generated record production, Adjusted EBITDA and proved reserves. We increased our annual production by 33% to just over 19,600 barrels a day despite the infrastructure issues and severe winter weather that impacted the Permian production. We’ve increased our Adjusted EBITDA by 38% to approximately $273 million, and our proved reserves by 5% to about $88 million. I’m especially pleased with our proved reserves, knowing that this figure didn’t include any of our horizontal Wolfcamp potential that is scattered through the Midland Basin, we get 27,500 acres in the Midland Basin that looks to be perspective.

Our integration of the 2012 Concho Acquisition, which was the largest in our history, went very smoothly this year, thanks to the hard work and dedication of our great employees. To more effect, we’ve managed this larger asset base, we grew our employee base by about 20% in 2013. It’s exciting for me to see all the new faces in the office and the good work they are doing. As I think back to this time last year, I remember the numerous questions we received asked to us regarding could we tackle a package this large? And I’m thankful to report that our results this year prove our capability, the team did a fantastic job of re-integrating those assets.

On the acquisition front, we closed 16 acquisitions of oil-weighted properties for about $108 million in 2013, of which 90% were in the Permian. Although we pursued a record number of opportunities, we fell short of our goal of $200 million for couple of reasons. The first is, we really focused on digesting Concho. But the second maybe the more of a challenge which was – this is the hottest year I can ever remember in time. With the horizontal boom going on, every package went for a significantly premium PDP. You know Legacy is a traditional PDP buyer and it’s tough for us to pay for upside, especially when we haven’t even started drilling our own Wolfcamp locations. So it was a tough acquisition year on that front.

As I look at 2014, I’m excited about acquisition prospects. I look back over to the last couple of years, we’ve closed 33 deals for $740 million. If you look back 2006, we’ve done 120 deals for $1.6 billion. And so even though the timing from acquisitions is unpredictable and you don’t know when they are coming, I’m really encouraged that we’ve got a good pipeline of acquisitions coming down the line and we’re looking at the right things. I think if you look at the right things, eventually you’re going to get your share, we’re going to continue to do what we’ve always done which is do good evaluations and try to be vigilant in our approach there. I’m particularly think that you’re going to see us buy some gas.

And 2014 as I look at, the companies that are trying to fund their oil drilling opportunities, they seem to be want to monetized more gas than oil. So it seems like that maybe a direction we’re going and an opportunity to buy things that other guys – we’re generally value buyers and look to buy the right things when other guys are wanting to sell them. So, I’m encouraged. I think 2014 is more likely to look like 2012 on the acquisition front than 2013 and I’m very hopeful about that.

On the development front, I’m pleased with the results of our oil-focused drilling efforts in the Permian. Our one-rig Wolfberry program continues to go well with our horizontal Bone Spring drilling outperforming expectations. In November, we had another well and did comparable results to the impressive wells that we added September of 2013 and November of 2012 wells, so both spring programs going well.

In 2014, the Board approved a $100 million capital budget for 2014. Regarding the key contributors of this operated program, you’ll some more Wolfberry drilling, you can see some horizontal Bone Spring drilling, and little bit of a change, we’re going to spend about $10 million capital, this is going to be long-term focus on some waterfloods and CO2 work. While this capital generates no incremental 2014 production, this is the right thing for us to be doing for the long-term benefit of the Company and the unitholders. So you’ll see the results of that work in 2015 and 2016 as those waterfloods come on. But as you know, when we – we do waterflood work, we’re actually taking some production offline in order to start injecting in those results on a longer term. But we try to do the best for the reservoirs. We’ve always said we’ll try to get more oil out than we already know is there and waterflood is one of the ways to do that, and it just didn’t have to be immediate impact that drilling does. Long-term I think that will be really good for the company.

On the non-operated front, our partners seem to have some really good plans and we’re encouraged by this. We’ve got horizontal Bone Spring works, of Yeso works, and Bakken wells, horizontal Wolfcamp well that’s going to come in. The Bakken is wading. Did you guys remember we brought the summer acquisition, I think it was 2012 acquisition that came with some acreage, our windings get some prong horned work that looks really good and they’re telling us that we’ll see AFE’s later the year. Pioneer, we’re – we made a deal with Pioneer to partner with them, those wells have some pretty good net interest, unfortunately because we haven’t been AFE yet we don’t expect that work – probably the non-op work is going to be heavily weighted towards the back half of the year because we hadn’t seen the AFE’s yet but we expect that work to be good work and to come late in the year.

So, on hold for the year and despite the impacts of third-party infrastructure and severe weather, we generated outstanding operational and financial results for 2013. Again, our strong performance and our promising acquisition outlook, the attractive development inventory, we increased our distribution for the 13th consecutive quarter to $0.59 per unit, resulting in a year-over-year distribution growth of about 3.5%. For the year, we generated distributable cash flow of $150 million, covering our annual distribution by 1.12 times. It was a great year for the unitholders, great operational year, and I’m really encouraged about what I see for 2014 on the acquisition front, and I’m encouraged that we’ll have a good year acquisition-wise and operationally fronting. So, we felt good about it.

And with that, I’ll turn it over to Dan, and let him cover the results in more detail.

James Daniel Westcott

Thank you, Cary. I’ll start this morning with more detail on our 2013 results, then move to our Q4 results. Ill then touch on some updates to our hedged portfolio and finally, walk through the highlights of our 2014 guidance.

As Cary mentioned, Legacy had another strong year in 2013 as evidenced by our 25% total unitholder return and record operational and financial results. Given the fact, insiders hold 80% of the same units outstanding, I can say that we certainly enjoy that performance just as much as you guys. From a financial standpoint we generated record production of 19,668 BOE’s a day due to a couple of factors. One, a full year impact of our $635 million of acquisitions in 2012, notably our $500 million contract position. Two, a $108 million of acquisitions of oil-weighted properties in 2013. And three, our record $94 million of development activities that were primarily focused on oil-weighted projects in the Permian.

That program as Cary mentioned, included our Wolfberry drilling program and two operational, operated horizontal Bone Spring wells that were completed in the late 2013. These increases were partially offset by third party infrastructure issues that mostly impacted our natural gas production in the Permian throughout the year, as well as the impact of severe winter weather in Q4. Along with increased production, we also benefited from a 6% increase in our realized oil price which was $4.84, and was primarily attributable to an increase in WTI of $3.93. Our average realized gas price increased 5% to $4.60 per Mcf from $4.38 per Mcf in 2012 which reflects an $0.87 increase in the average WTI index – excuse me, Henry Hub index price. That was offset by positive – by lower positive differentials. So as a reminder, we sell wet gas in the Permian and we have a – as a company-wide we sell the premium to Henry Hub, that positive differential decreased this year from a – due to a curtailment of our – some of our NGL-rich gas.

As an offset to these increased prices, we paid cash settlements of $7.1 million on our commodity derivatives compared to – which is comprised of $14.2 million paid on crude, and $7.1 million received on natural gas, this $7.1 million paid this year compared to $5.9 million received in 2012.

Covering expenses, LOE increased to $142.8 million or $19.89 per BOE from $103.4 million or $19.08 per BOE in 2012. Production expenses increased primarily due to acquisitions, and remedial workovers, and other well failure expenses associated with those acquisitions, most notably, our Concho and Resaca acquisitions.

G&A excluding the LTIP expense for the year totaled $24.1 million compared to $21 million in 2012 which was mostly attributable to an increase in salary and benefit expenses related to hiring of additional personnel to manage our larger asset base. Finally total development capital increased to $94 million in 2013 from $68.2 million in 2012, as we continued our Wolfberry program throughout 2013, drilled two horizontal Bone Spring wells late in 2013, and increased our other operated and non-operated drilling and capital workover activity, most of which was in the Permian. Our non-operated capital expenditures were 27% of total for the year and that compared to 23% in 2012.

In total, Adjusted EBITDA increased 38% to a record $272.7 million, that’s up from $197.6 million in 2012, as the impact of increased production and commodity prices was partially by – was partially offset by increased expenses and cash settlements paid on derivatives. 2013 was also a notable year on the capital markets front. We positioned our balance sheet for future growth with an opportunistic offering of $250 million of senior unsecured notes at an attractive interest rate of 6.625%. Due to this financing and the increase of our borrowing base in late 2013 to $800 million, we have approximately $465 million of availability as of February 1, which we would like to use to fund future acquisitions and development projects.

So now when we dive into Q4, as we announced on December 4, 2013, and as reported by other operators, severe winter weather and infrastructure issues negatively impacted fourth quarter operations in the Permian. While we experienced no material long-term property damage, our production was temporarily curtailed or shut-in throughout numerous fields. This anomalous event created a shortfall in production and corresponding cash flow. We generated production of 19,402 BOE’s a day in Q4 which is a 3% decrease compared to 20,043 in Q3, primarily due to weather and ongoing third-party infrastructure issues. These negative factors were partially offset by strong production from two operated Bone Spring wells, which initiated production in early September and early November, as well as some small oil-weighted acquisitions. The net of all this yielded disproportionately negative impact to our natural gas production, which declined 8% compared to the third quarter while liquids production remained relatively flat.

On the pricing side, our average realized oil price decreased 13% or $12.77 a barrel compared to the third quarter as WTI decreased approximately $8.33 and differentials deteriorated in the Permian and more so, in the Rockies. The Midland-to-Cushing differential widened to negative $2.36 per barrel from negative $0.29. So we had 8,000 barrels a day hedged at negative $1.47 which mitigated this exposure. We expect Midland-to-Cushing to be about $2.75 per barrel to $3.75 per barrel in the first quarter of 2014, and hedged approximately 1,450 barrels a day at negative $1.75. Average realized natural gas prices increased 16% to $5.03 from $4.34 in the third quarter due to an improvement in the positive differential to Henry Hub prices, that really reflects NGL prices in the Permian Basin.

Given our production mix, the prices that I just talked about had a net decrease on a BOE basis, and in addition to this net decrease on a BOE basis, we paid $2.4 million in the fourth quarter on our commodity derivatives as compared to $6 million in the third quarter. Lastly, on the hedges I’ll note that the decrease in WTI between September and December resulted in a negative one-month hedge lag effect of $2.2 million.

On the costs side, LOE for the quarter increased 8% to $39.5 million or $22.12 per BOE from $36.7 million or $19.88 per BOE in the third quarter. This increase was primarily due to higher workover and other well failure expenses of an incremental $1.5 million. G&A excluding the LTIP for the fourth quarter declined slightly to $6.4 million compared to $6.6 million in the third quarter.

Finally, total development capital expenditures increased to $28.6 million in the fourth quarter compared to $26.1 million in the third quarter. Our level of operated activity was similar to that in the third quarter, as we compared – as we continued our Wolfberry drilling program, drilled and completed the second of our two operated Bone Spring wells, and engaged in several other recompletion, capital workover and drilling projects, mostly in the Permian Basin. Both Bone Spring wells completed in September and November generated strong initial results and our Wolfberry program continues to deliver. Our non-operated CapEx, which was mostly in the Permian, increased in the fourth quarter and accounted for approximately 27% of our total development capital as compared to 18% in the third quarter.

Now regarding our hedge portfolio. As we mentioned in our release, we recently made some pretty significant additions and changes. In December we completed a costless restructuring of our 2014 oil three-ways that had $90 or $85 long puts, we exchanged these for swaps with identical volumes and tenors at an average price of $95.49 per barrel. This move further stabilizes our 2014 cash flows at an attractive oil price. In addition, we took advantage of the recent surge in natural gas prices due to abnormally cold winter weather and hedged most of our exposure – most of our dry gas exposure in 2015, as well as a portion of our 2016 exposure. I’ll note that in our release we normally provide our up to date current hedge portfolio but we also highlight the changes since our last disclosure.

Finally I’d like to talk about our 2014 guidance. Before we talk about specifics, I’d like to point everybody to our press release, and the naturally word of warnings we have provided in paragraph form. Please take those seriously and recognize that this is our current view of future projections assuming no further acquisitions. Now that being said, the midpoint of our production guidance was 19,500 BOE’s a day, reflecting our PDP and development of our attractive capital opportunities that Cary and I have discussed. This maybe a bit lower than some of you would expect, so let me add some color.

Firstly, we plan on spending $10 million of long-term focused capital that will produce no incremental rate in 2014. This includes the operated and non-operated waterflood projects and a small amount spent on the Tier II project. While a short-term view may indicate otherwise we believe these projects are consistent with a long-term sustainable approach of an MOP. We’re deploying capital for the long-term good of our unitholders and not just for 2014.

Second point I’d make about our 2014 capital is that our most productive capital, namely our operated Bone Spring wells is currently scheduled for late 2014 due to the Prairie-Chicken speculations in New Mexico. This results on a smaller production impact in this calendar year. In addition, while we have done a better than anticipated job at mitigating the client in the Lower Abo, the efforts that we have in Concho. We still experience much higher than average decline rates from these assets in our 2014 forecast.

Moving down the guidance list, next to differentials, we’ve provided all guidance of $6.25 to $7.50 of WTI. NGL per gallon guidance of 1% to 1.1% of WTI or said differently, 42% to 46% on a barrel basis. In a positive natural gas differential of $0.95 to $1.05, these differentials specifically include the impact of any commodity derivatives currently in place – excuse me, exclude [ph].

On the expense front, the midpoint of our LOEs per BOE guidance of $21.65 is notably higher than our $19.89 per BOE from 2013. Our Resaca acquisition drove our $1 per BOE LOE metric up. More importantly, however, after fourth quarter in which we realized just over $22 lifting cost, we’re not comfortable assuming the contraction in workover expenses. This year we lumped Ad valorem and production taxes into a single category with a range of 9% to 9.5%.

G&A in guidance is $28.6 million to $30.1 million. I think that’s pretty straightforward. We plan on continuing to grow our headcount as we built towards the future. We previously discussed carrying on both, the $100 million capital program, I pointed out that our estimated maintenance capital for the year is $71.2 million which also ties to our current Q4 run rate.

So as I walk through these numbers I’m hopeful for add a little bit more context of our expectations for our current assets. I know each of us here at Legacy needs to meaningfully grow our business. We hope to exceed these numbers and we hope to make 2014 another outstanding year for Legacy.

From my chair and a financial perspective, I see our attractive hedge portfolio, favorable capital markets conditions, and ample availability under our credit facility, all of which position us to execute on our growth initiatives in 2014 and beyond.

In closing I’d like to echo [ph] Cary and say that we’re thankful for the hard work for our employees, and the record results they helped produce in 2013. And at this time, Cary and I, as well as the rest of the management team will like to take your questions.

Question-and-Answer Session

Operator

(Operator Instructions). Our first question today comes from the line of Dan Guffey of Stifel Nicolaus. Your line is open, please go ahead.

Daniel Guffey – Stifel Nicolaus

Good morning, guys. Dan, just looking at guidance you provided for 2014, production guidance I understand it’s assuming no acquisitions but production is relatively flat year-over-year and then looking at the CapEx for 2014, a $100 million total CapEx with $71 million is going to be maintenance, at least to $28.2 million for growth, and I understand $10 million is going into long-term waterfloods that won’t be – the results of which won’t be seen in 2014, but that leaves approximately $18 million in growth CapEx. I’m just curious how that relates to your production guidance?

James Daniel Westcott

Sure. I think your question is really driving towards maintenance capital because I would point out that – the working guidance includes both, the flood and probably drilling. So, if you know, what I’ve highlight is, we’ve talked about what’s included in our $100 million capital budget, and if your question is really around total numbers and the maintenance number, I guess I’d point it back to how we’ve been talking about maintenance capital now for a year or so since we started it which is not aimed at maintaining any year-over-year production but is – but really looks at on a long-term basis. I think we’ve added some disclosure this year in our Bcf reconciliation, that’s where annual lease [ph], highlighting that and trying to give some more color there but we do look at it on a long-term basis and we feel like it’s – after looking at it in six, seven or eight different ways, we feel like it’s an appropriate measure.

Daniel Guffey – Stifel Nicolaus

Okay, thanks. And Cary, you mentioned in your opening remarks about the value that unconventional horizontal players are now getting throughout the Permian. Have you guys looked at potentially entering into any JVs or farm outs or divesting a portion of any of your acres that has horizontal development potential?

Cary Brown

We’ve talked about that and right now we have – I think [indiscernible] is $25,000 in acre, I’m a seller, not a buyer. So I’ve said that publicly but our acreage footprint is pretty scarce, so it lends itself more to – like what we did with Pioneer, partnering it on well and that kind of thing rather than just stand up a rig and go on drilling. So even though it’s a good acreage position, it’s not a concentrated acreage position which makes it hard to do a JV. We’ve looked at some, I wouldn’t say we’re not entertaining those ideas but I have not seen a JV that I would say is better for others than to continue to take the disciplined approach of just developing that as it comes.

Daniel Guffey – Stifel Nicolaus

Okay, great. And then one more for me, it’s with – what you’re seeing in the Permian, the back rotation [ph] of oil curve and Cary you mentioned shifting your focus towards gas in 2014. Does that mean you’ve shifted your focus towards acquisitions in other basins, and if so, are you looking for both, on acquisitions in the Rockies and/or Mid-Cont?

Cary Brown

I would say we’re very active in looking at other basins. We still, Permian’s are our home basin, we’re looking at everything that comes through on the Permian and I wouldn’t be surprised to see us through these Permian deals. But we’re very interested in growing that through the middle part of the country. If you look at Texas, to the Canadian border, kind of north, that’s where we would like to grow, we see some attractive assets in the Mid-Cont and in the Rockies that – I would say, long a lot [ph] gas looks really attracted to us right now.

Daniel Guffey – Stifel Nicolaus

Okay, thanks guys. I’ll hop back in the queue.

James Daniel Westcott

I appreciate it Daniel.

Cary Brown

Thanks Dan.

Operator

Thank you. Our next question comes from the line of Kevin Smith of Raymond James. Your line is open, please go ahead.

Kevin Smith – Raymond James

Thank you. Good morning, gentlemen.

James Daniel Westcott

Good morning, Kevin.

Cary Brown

Good morning, Kevin.

Kevin Smith – Raymond James

Would you mind providing kind of a range, how much production is returned when the wells freeze-off? What’s kind of the new normal versus 4Q’s range for production?

Paul Horne

Yes, Kevin, this is Paul Horne. We’ve already been asked numerous times exactly how much production was curtailed in Q4 due to the weather. Let me start by saying, it was actually more than weather, we had three separate events occur, starting late November, the first of which was a water well drilled in – a water well drilling rig drilled into a Portland that transports NGLs from the Permian. One of the major NGL transmission lands that caused a significant disruption. Before that was back up and going and everything was back online, we had the first hard storm freeze, right at the end of November. And then, again before that got completely resolved and everything back online, we had the second one of those. So, it’s pretty difficult to nail down Kevin and say here is exactly how much production was lost due to the NGL pipeline rupture, the first storm and the second storm suffice it to say that it was material although it’s not pretty material to me. I would say that over the quarter we had several hundred barrel a day impact – that number could be higher than that and I – we’ve done some analysis that says it maybe. We’ve got all of that production back online – we actually had that production back online. And by mid late December, we were impacted with how much oil we could get out of the field because of weather related issues. But January and February has been awfully cold for West Texas and we continue to see those issues and we’re working on those. Interestingly enough, our operations were at really cold places like Pampa, Texas and Wyoming, Montana, North Dakota have done a great job with the weather. They’ve had as hard a winter as everyone else and yet – because they are prepared for the weather they’ve done a great job and it’s helped us in the Permian where we’re not quite as used to.

Kevin Smith – Raymond James

I appreciate the color. Are we going to be – I guess the next follow-up question on that, are we going to be talking about weather in Q1 based off what we’ve seen so far in January and through February till date?

Paul Horne

We’ll talk about that at the end of the quarter. I will tell you today, absolutely January was difficult due to those exact same issues. We’re seeing that production recover nicely, the weather is really warmed up and – so, I am hopeful that the second half of Q1 with what we’ve seen over the last couple of weeks offset that and I don’t have to spend a lot of time talking about that Kevin but January was tough month.

Kevin Smith – Raymond James

Got you. Thank you very much. One other question on your waterflood program, can you give us some information about maybe where the capital is being spend, and when and how much production you plan on taking offline for it?

Paul Horne

Sure. That $10 million is actually scattered over three different projects, the most significant portion of the capital was being spend on our Resaca acquisition. On the Cooper Jal unit we are doing some conversions, some drilled wells, adding waterflood in several patterns that has never been effectively waterflooded, the waterflood was very ineffective in those areas that constitutes about half of that $10 million. The other five is split evenly between some waterflood or that I’m – that I’m also really excited about, from our Concho acquisitions in Fullerton field. We feel good about that work and anticipate that really helping with the long-term results of the Concho acquisition. In that particular project we’re going to take about a 100 BOE’s a day offline. We’ll get back – we’ll start getting that back so that it doesn’t have a negative 100 BOE a day impact for the year. But when we put the third project in which is non-operated CO2 capital in the Oxy-operated hubs field, our total $10 million has net got some gain of growth [ph] in 2014 but good rates of return that we’re excited about and feel like it’s the right answer to spend for 2015, 2016 and beyond.

Kevin Smith – Raymond James

Okay. And then, lastly for me and I’ll jump off, any information you can share with on the impairment charge?

Micah Foster

Yes, Kevin this is Micah Foster, Chief Accounting Officer. Impairment this quarter was primarily kind of our natural gas differentials, a little bit by higher LOE’s but primarily natural gas differentials is somewhere in our region [ph]. We do impairment at the field level, and those differentials are typically only updated annually when we have road show outside, our reserve engineer prepare them for us. So, that was the main driver there.

James Daniel Westcott

Yes, this is Dan. I commented it was the differentials but in addition to that when the impairment is done we look at the forward curve and the tail price on the forward curve this year is lower than last year, at least what the yearend pricing that was, maybe not since the cold weather but when we did that test it wasn’t. So, we’re kind of had a double whammy of lower differentials and a lower forward curve.

Kevin Smith – Raymond James

Okay, thank you.

James Daniel Westcott

Yes.

Operator

Thank you. Our next question comes from the line of John Ragozzino of RBC Capital Markets. Your line is open, please go ahead.

John Ragozzino – RBC Capital Markets

Good morning, gentlemen.

James Daniel Westcott

Good morning, John.

John Ragozzino – RBC Capital Markets

Perhaps this one is for Cary. Can you try and compare the current AMD market environment in the Permian and the associated opportunities that basically have Legacy with the environment and the associated opportunities that are of prior years. Just keeping in mind all the recent horizontal activity in the – associated at the basin right now?

Cary Brown

So, firsthand the question you’re asking, how does the current environment compare to previous environments, and –

John Ragozzino – RBC Capital Markets

Yes, and what’s the net impact on the opportunities that are faced by you guys?

Cary Brown

So I would say that the volume of deals that we’re seeing is good. I’m not disappointed by the amount of deals. The value being described to acreage today has gotten so large relative to the PDP that it is hard for us to justify and it really – I don’t know that I’d say that guys are overpaying acreage but for Legacy to go about drilling opportunities, we can’t fully go after our current inventory of drilling opportunities seems like a bad use of year holder [ph] dollars. So I think there is good opportunity, I don’t – I really like what I see in terms of – look at the capital that has to be spent to execute on the drilling opportunity, we’re getting a lot of enquiries of guys of – how can I sell you the PDP and use that cash to go drill. And so we look at that, so I think for future it’s a really good pact pattern for us, you know we try to pride ourselves being the best operator in the Permian and we think we are really at operating PDP production, and ultimately all of these horizontal wells are going to come back to us. So, I think we’re in good shape but I would tell you if it’s a Midland basin oil deal, it’s going to be hard for Legacy to go out and compete on that. We see other things, there is some gas that comes for sale that I think we can compete on, and then other basins and you know, we found – you look at Resaca deal, that’s a deal that wasn’t counted as a horizontal play, it’s got waterflood potential, but that’s a long-term play, it’s not something you drill and see. So I think ultimately, we’ll continue to be able to execute our business plan but the challenge right now is, prices are pretty tough. And then I’d also add, when you look at the forward strip, I don’t think that on the oil properties you can be very competitive today if you’ve been in the forward strip.

John Ragozzino – RBC Capital Markets

I appreciate the color. Does that perhaps suggest that you are more willing or more likely to set outside of your core Permian focus and then perhaps, look to other basins for opportunities?

Cary Brown

Yes.

Kyle McGraw

Yes, John, this is Kyle McGraw, Chief Development Officer. And I would say with our offices at Cody, Wyoming; our office at Pampa, Texas; we have been looking continuously to cheer for those other basins, we consider those – on Permian’s where we have or corporate headquarters are, we have been looking to those other basins. And so, I’ve just come back from the North American prop-expo and assume they have found a record attendance, the overall atmosphere was very good. More significantly, leads from that event that I had seen in previous years. And so, it’s just a finger on the pulse, I’m getting a more big marketed transactions, big gas transactions that are available and are out there and we’re playing to be numerically some process on those. So from just a visibility, from that standpoint I’m saying big company monetize the assets that maybe you’re gas [ph] or in basins that they are not introducing in, it just looks like they are focused to elude that to the Permian. So we are very interested in those and I have a great visibility on some of those.

John Ragozzino – RBC Capital Markets

Great, thanks very much. And just one more for Dan, you mentioned the positive differentials you’re seeing for the wet gas production that you guys have. Can you comment on the current state of those given the recent spike in NGL prices that both [indiscernible] have they returned to normal levels, are they north of where they were, if you call three months ago?

James Daniel Westcott

Absolutely. Yes, we are seeing that, we’re enjoying it. If you look at our – I guess I would urge you to look at our Henry Hub price realization. We’ve now changed up our results of operations, our disclosure this quarter and we’re now providing kind of average index for people on our eyes, and if you compare that, it looks like we were above 43 over Henry Hub in Q4, which is a pretty dramatic change over Q3 but it still feels good about the guidance we gave, if prices hang in there where the NGL prices hang in where they are, we might – we could very well see better than that. But from a planning perspective, we want comfortable – just dragging current prices up to the right.

John Ragozzino – RBC Capital Markets

Fair enough. Thank you very much gentlemen. We’ll catch up within three months.

James Daniel Westcott

Thanks, John.

Operator

Thank you. Our next question comes from the line of James Spicer of Wells Fargo. Your line is open, please go ahead.

Unidentified Analyst

This is Patrick [ph] for James Spicer. Looking at your G&A guidance, and it looks like you’ve applied something north of 20% on a year-over-year increase with respect to the cash G&A. I mean, I’m just wondering what is driving that increase.

James Daniel Westcott

Sure. Well, it’s primarily an added personnel. So I think we’ve got a dozen or so, plan new hires on a net basis for 2014, that increased salary as in wages. And then, I guess – you can look at it on a run rate comparison so Q4 run rate to – for 2014 because we added a woman’s [ph] office in July of 2013 with added personnel there as well and so, it’s nothing magical there other than an added personnel. That in the way I would respond to that is, we didn’t have all the employees we needed for our December 2012 Concho acquisition on January 1, 2013. It took us the majority of the year to hire that manpower and – so all of those employees that have helped us with that didn’t have a full year impact in 2013 and we’re projecting that they will have a full year impact in 2014, really pleased with the additions that we made and feel like that was a big reason why we had the success we had in integrating the Concho acquisition.

Unidentified Analyst

Okay, alright. I’m wondering could you possibly provide what the overall PDP decline rate of your asset base is right now.

James Daniel Westcott

We don’t provide that. So, I think what we characterize and talk and give plenty of color on asset, kind of, more general or more specific asset bases but that’s a key characteristic of our business, it’s one that we pride ourselves on. And when we look at Permian long-term decline, we see that in a long-term decline of 68%, we’re focused on managing that very tightly and moderate our drilling program to control that.

Cary Brown

Yes, Dan I was going to go back and actually add a little bit for Dan Guffey’s question, I didn’t get the chance to jump in on that. I think one of the things you’re seeing and this shouldn’t be a surprise to any of you, we started talking about it in December, and I believe we have talked about it every quarter since. There was a portion of the Concho acquisition, specifically the lower horizontal production, that we told you guys was not in the light that it really was in MOP [ph] and we were going to chase that rate, we did not build or making its capital to offset that rate. We had a plan of allowing that to decline off. And when you have that significant portion of your asset base declining at relatively higher rate underneath, it has an impact and you’re seeing that. But fortunately, in 2013 because of some outstanding results from our capital program in several different places, you didn’t see that underlying decline happening quarter-over-quarter and yet when we come to the end of the year and do a reservoir for and do our future projections, it impacts the guidance. The other thing that is impacting our guidance on a PDP basis is, you heard us every quarter talking about infrastructure issues, the impact of that on your gas production, and therefore NGL production and even some impact on your oil production. And when you have that ongoing for a year and then you do your decline curve analysis and work on a go-forward basis, that’s going to have an impact on your PDP production as well.

John Ragozzino – RBC Capital Markets

Okay. But I guess with respect to this lower able assets, do you have an idea when you think the decline there is going to flatten out or do you have an idea about the timing and where it’s not – you know, it’s not going to be offsetting your organic growth?

Cary Brown

Sure, sure. Its decline is significantly less in 2014 than it did in 2013, in fact, less than half on a barrel basis. And within the next two to three years it will be a typical Permian decline rates. The bad news about it is that it has declined significantly since we bought it, the good news about that is then the decline rate is not nearly as high. And so I do not think it will have this significant an impact in 2014 as it did in 2013, and I believe by 2015 it will be a non-event and you’ll hear me shut up about it and not talk about it anymore.

John Ragozzino – RBC Capital Markets

Okay. Could – would you be able to provide what the production numbers are right now?

Cary Brown

No, we don’t give point in time production rates. What I’ll tell you is, we feel good about our guidance, not seeing anything that has me panicked, not seeing anything that says that we’ve low bowled [ph] and set an easy target after.

John Ragozzino – RBC Capital Markets

Okay, thank you.

Operator

Thank you. Our next question comes from the line of Praneeth Satish of Wells Fargo. Your line is open, please go ahead.

Praneeth Satish – Wells Fargo

Hey guys, good morning. Just two quick questions for me. I guess the first, just to be clear does your full year production guidance, does that include the impact of whether disruptions that you’ve seen so far in January and part of February?

James Daniel Westcott

Yes, it does.

Praneeth Satish – Wells Fargo

Okay, good. And then the second question, I guess historically you’ve had a fairly consistent predictable track record of raising the distribution, about half a penny every quarter, has anything changed there based on what you see with your 2014 guidance, maybe are you looking at it more opportunistically with acquisitions or are you still comfortable with the current strategy?

James Daniel Westcott

No, great question and when I’m trying to give you little bit more color on. Yes, I would love to do that, I think each of us here in the room would love to continue to increase it and we’d love to increase it by $0.10. But that’s a determination that our Board makes on a quarter-by-quarter basis and we’ll take it as it comes. So, we said before, we want to grow our distribution at 3% to 5%, and we will need to make acquisitions to make that happen. And so, I think we’ll take it as it comes and if you guys recognize our goals and what we need to do, like I said in the prepared remarks, we want to make acquisitions and beat all these numbers but as we look at our current asset base, that’s what we see.

Praneeth Satish – Wells Fargo

Okay, great. Thank you.

James Daniel Westcott

Okay.

Operator

Thank you. (Operator Instructions). Our next question comes from the line of Abhi Sinha of Wunderlich. Your line is open, please go ahead.

Abhishek Sinha – Wunderlich Securities

Yes, hi, good morning everybody. Just a quick one, a follow-up on the Lower Abo decline rate. I mean, have you guys – are all these wells have been producing or is any well that you need to be drilling there? The reason I’m asking is I’m trying to see if there is any more well that needs to be completed, can you make any changes to the completion technology to offset that decline or lower the decline rate that you are facing?

Paul Horne

Yes, this is Paul Horne, I’ll answer that. All wells were completed online when we made the acquisitions in December of 2011, they were relatively new wells, anywhere from a couple of months old to less than a year old. We do have two or three pipes on our books in the Lower Abo and are looking at those, they are not in our current 2014 drilling plan, they are further out 2016, 2017. There is some PVNT [ph] in our plan for the Lower Abo, some additional work that we’ve seen and feel like we can do to help those wells with that decline. That answers your question?

Abhishek Sinha – Wunderlich Securities

Yes, sure. Thank you very much. That’s a lot.

Paul Horne

Thanks, Abhi.

Operator

Thank you. Our next question is a follow-up from the line of Dan Guffey of Stifel Nicolaus. Your line is open, please go ahead.

Daniel Guffey – Stifel Nicolaus

Hi guys, just one follow-up. The Bone Spring wells that you guys have drilled in 2012 initial results from one of the wells unlike 2013 looks to be outstanding. I’m just curious, you plan on drilling a few wells, Bone Spring wells this year, well maybe offsets to that late unit and if not where would those be located?

Cary Brown

Yes Dan, we’re going to drill two – our current plans are to drill two wells on our Hamon Federal Lease which is what three miles west of our late unit that was the last well that we drilled was on the Hamon, had great results, we’re very, very excited about it. The only downside to it it’s not as impactful as late unit wells because it’s roughly 50% working interest and 40% in our eyes is oppose to about a $90 and $85 on the late units but we plan on drilling two of those and then on addition late unit well. So that’s the good news. The bad news is, all three of those wells are in the Prairie-Check [ph] area, not going to get those wells online until Q3. The first seven will come online in Q3, the last seven will come online in Q4. So, it doesn’t have the impact that we would like it have on a year-over-year basis because you’re going to get to have less than half of your production rate.

Daniel Guffey – Stifel Nicolaus

Okay, that’s helpful. And then, did you guys mention you petitioned it partner in a Wolfcamp well this year, where will that be located?

Kyle McGraw

The well is located in Martin County, and it’s in partnership with Pioneer.

Daniel Guffey – Stifel Nicolaus

Okay. Thanks guys, I appreciate the detail.

Cary Brown

Thanks Dan.

Operator

Thank you. And that does conclude our question and answer period. I’d like to turn the conference back over to Mr. Westcott for any closing remarks.

James Daniel Westcott

Thank you. Thank you, everyone for dialing in this morning. We appreciate the good questions, and your continued support. As I mentioned at the onset of the call, we plan to file our 10-K tomorrow, so hopefully that incur has additional disclosures and detail for all of our investors and interested parties. I’d encourage you guys to read that. And as always, if you have additional questions after today’s discussion, please don’t hesitate to reach out to me. Thanks again.

Cary Brown

Thanks guys.

Operator

Ladies and gentlemen thank you for participation in today’s conference. This does conclude the program, and you may all disconnect. Have a great day rest of your day.

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