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EV Energy Partners, L.P. (NASDAQ:EVEP)

Q1 2014 Results Earnings Conference Call

May 12, 2014, 09:00 AM ET

Executives

John B. Walker - Executive Chairman.

Michael E. Mercer - Chief Financial Officer

Mark A. Houser - Chief Executive Officer

Analysts

Kevin Smith - Raymond James

John Ragozzino - RBC Capital Markets

Abhishek Sinha - Wunderlich Securities

Operator

Welcome to the EV Energy Partners' First Quarter 2014 Earnings Conference Call on Monday May 12, 2014. Throughout today’s presentation, all participants will be in listen-only mode. After the presentation, there will be an opportunity for analysts to ask questions. This morning, EV Energy Partners' issued a press release announcing quarterly results. That release along with additional financial and operational information and reconciliations for non-GAAP financial measures is available on EVEP's website at www.energypartners.com.

Please refer to the forward-looking statements in the earnings press release, which state that statements made during this call that refer to management expectations and or future predictions are forward-looking statements intended to be covered by the Safe Harbor provision of the Securities Act, as there are many factors which could cause results to differ from the management's expectation.

I will now hand the conference over to John Walker, Executive Chairman. Please go ahead sir.

John B. Walker

Thank you, [Telpin]. Mark Houser is here with me in Colorado Springs which is very frigid. And thank all of you for joining us; this is annual institutional investor conference for EnerVest over the next two days.

We have made progress at in EVEP on many fronts this spring and some of the results are reflected in the first quarter. First, thanks to the good work our operating teams, our overall operational performance was strong, particularly taking into account the weathers impact on our upstream, but more specifically our midstream operations.

Production was above guidance midpoint with overall expenses in capital spending inline. We also continued to see good results in the early Eagle Ford drilling underneath our Austin Chalk assets. The wells that we have drilled with Halcon and Apache continued to improve on both cost and IP rates. In Brazos County, they were also demonstrating consistency and repeatability at this early stage, it’s very encouraging.

Mike Mercer and Mark Houser will speak to you more on the specifics in a few minutes. Our biggest progression point has been in our Utica midstream investments, which includes our 21% investment in UEO processing and fractionation and the 9% investment in the Cardinal Gathering business.

In our year end call in February, I indicated there would be a significant ramp up to throughput and cash flow throughout the year and that ramp up is happening.

Now that the midstream bottleneck is being addressed, volumes from the wet gas vendor in Carrol and surrounding counties continue to come online and grow almost each week with wells [indiscernible]. As you are aware, the UEO system dominates the part of the wet gas window. We have 400 million cubic feet of daily nameplate capacity available through the first two trains at Kensington; we have retained peak production levels approaching 450 million cubic feet per day through these two trains on several days over the past month.

Processing train three, began its start up process on April 24, it’s slated to be fully in service by June 1, bringing nameplate capacity to 600 million cubic feet per day. Based upon what I just said about “nameplate” and capacity in the improving efficiencies of our plate, the 600 million cubic feet per day nameplate we believe will translate into 660 to 720 million cubic feet or 320% higher actual processing capability.

In our Harrison Fractionation facility Frac 2, Frac train 2 was also commissioned on April 24, doubling nameplate frac capacity to 90,000 barrels per day. The Harrison Fractionator efficiencies also are experiencing the same path of expansion is our processing plant based on nameplate, so we are about – we have the ability to fractionate 10% to 20% more than the 90,000 barrels per day.

We remain extremely pleased with our operated momentum and their ability to keep these projects on time, on budget and operating at high levels. It was also announced this morning that UEO had reached agreement regarding new processing and fractionation commitments from the Chesapeake Total EnerVest joint venture and from a new customer American Energy Partners. These agreements will expand our area of dedication and UEO plans to increase nameplate capacity from 800 million cubic feet per day to 1 billion cubic feet per day. UEO also has agreed to provide gathering, compression and dehydration services for American Energy Partners.

The new long-term agreement between UEO and AEP includes a 145,000 acre area of mutual interest. In addition, the UEO expansion plans include the extension of a high pressure pipeline from the Harrison hub to a Cardinal compression facility extending UEO’s footprint further in Harrison County.

Additional services at the Harrison hub also included downstream liquids interconnect and expanded propane and butane storage. Momentum currently is finalizing specific capital requirements for this expansion. Once this plan is finalized, we will provide more detailed information on specific capital requirements and expected incremental cash flows.

Now turning to our Cardinal Gathering System. EVEP is I already said owns a 9% interest in Cardinal along with Access and Total. Cardinal gathers all production from wells within the 660,000 acre joint venture between Chesapeake Total and EnerVest.

As of the end of March, 495 wells have been drilled within this JV and only 274 wells were produced with the remainder awaiting pipeline connection on various stages of completion. Chesapeake plans to drill 180 wells this year and continue at their pace into the future.

I should note that during the 2014 first quarter, Chesapeake ran 9 rigs and connected 47 wells to sales with an average peak production rate of approximately 1,180 barrels of oil equivalent per day. This rate is higher than Chesapeake’s reported rates in the Eagle Ford and mid continent areas.

We believe that the productivity of these wells and wet gas winter wells generally and as part of the play will continue to improve with increased take away capacity and continued retirement to completion techniques. This has helped to enhance the value of the wet gas acreage as more production is gathered. Our strategy for upstream acreage sales in the wet gas window coincides with the ramp up in production.

As the weather has moderated and wells have continued to be tidy and throughput in the Cardinal system continues to increase, averaging 445 million cubic feet per day in April and that’s up from 100 million to 150 million in December. We anticipate continued growth as Cardinal further catches up with the existing inventory above our 200 wells being hooked up as well the newly drilled wells.

The JV projections call for 700 million to 800 million cubic feet per day at year end. As an important reminder, we have tag along rights with both midstream assets. Since we do not see ourselves as a midstream company over the long term, as opportunities present themselves which makes sense for EVEP, we will consider sales of these assets.

As I mentioned, Mike and Mark will provide color on our quarter from a financial and operational perspective. Before I hand it off, I just want to personally say that we appreciate your support of EVEP and are pleased with the progress we’ve made during this part of the year. Mike, could you provide the financial over view.

Michael E. Mercer – Chief Financial Officer

Thank you, John. For the first quarter, adjusted EBITDAX was $56.1 million, which is a 15% increase over the first quarter of 2013, and a 4% increase over the fourth quarter of 2013.

It was also above the EBITDAX that would have been – that would have result to using the midpoint of our prior guidance for the quarter, and actual NYMEX oil and gas prices for the quarter.

Distributable cash flow for the quarter was $28.6 million, a 31% increase over the first quarter of 2013 and a 7% increase over the fourth quarter of 2013. The increases in adjusted EBITDAX and distributable cash flow which are described in our press release table under non-GAAP measures are primarily due to increased production and increased EBITDAX from our midstream investments, which grew to over $3.5 million for the first quarter.

Distributions for the quarter, first quarter which are payable on May 15 to unit holders of records as of the close on May 9 are approximately $38.9 million.

For the first quarter, production was 10.8 Bcf of natural gas, 265,000 barrels of crude oil and 550,000 barrels of NGLs or 174.7 MMcfe/day. This represents a 6% increase over last years first quarter of 165.2 MMcfe/day and a 2% increase over the fourth quarter of 2013 production of 170.5 MMcfe/day. The increases in production are primarily due to drilling activity and some small acquisitions we completed during the fourth quarter of 2013.

Our first quarter net loss was $6.3 million, or a loss of $0.14 per basic and diluted weighted average limited partner unit outstanding. Several items to note that were included in the net loss are; $16.8 million of non-cash losses on commodity and interest rate derivatives, primarily due to changes in the value of oil and natural gas derivate contracts to settle in future periods, a $4.5 million of non-cash compensated related cost containing G&A, $2.3 million of payroll taxes related to cash costs contained in G&A expense that are associated with the annual vesting of our phantom units during the first quarter and which amount will not be incurred during the second through the fourth quarters.

A $1.5 million gain on the sale of oil and natural gas properties, and $0.3 million of dry hole and exploration costs. In March 2014, we entered into additional crude oil hedges for 2015 which are detailed along with our current hedge positions in tables at the end of our earnings press release. In addition, we recently completed as noted in our 10-Q our semi annual borrowing base review under our bank credit facility with the borrowing base we affirmed at $730 million.

I’ll turn it over to Mark Houser for a review of our year end reserves and our – freight and review of our operations.

Mark A. Houser - Chief Executive Officer

Thanks Mike. John has already mentioned the progress we’ve made in the Utica Wet gas and midstream areas for our focus on other upstream areas today, mostly on the Barnett shale and our Austin Chalk activities. But first, I’d like to comment on our Utica oil window efforts.

Our estimates of oil in place through most of Tuscarawas, Stark and Guernsey Counties is around 20 million to 30 million barrels per section. Ascending the midpoint, this is about 5.5 million barrels of oil in place for 140 acre well. Lets say 400,000 barrels per well is needed for attracting economics with a good, sustained flow rate initiating from the IPs of 500 barrels to 700 barrels a day, this represents recovery of around 7% of oil in place, very similar to reported recoveries in other oil shale.

The challenge in the oil window appears to be fracture design and minimizing reservoir damage upon completion. We are working with industry partners currently on some studies designed to help us better understand the flow capacity of the oil window rock. We still plan on drilling in the oil window later this summer and are closely monitoring on our oil window wells.

Now getting to the Barnett. I want to compliment our operations team for the job they did in managing production through the winter. While it was pretty much cold everywhere, in the Barnett, which accounts for over 50% of EVEP’s production, it was particularly tough. We had interruptions due to icing and freeze off in December, January, February and March. Despite these interruptions and why I consider slightly lower than expected inflows from our new wells, we were able to stay inline with our guidance for production, capital and expenses.

As a reminder, EnerVest is one of the top five Barnett producers and EVEP has a 31% in the EnerVest properties. This scale helps in many ways. Through the first half of the year, we have two rigs running in the Barnett. In the first quarter, we drilled 16 wells, a total of 12 were brought online with the average rate of 1.8 million cubic feet equivalent per day at an average drilling complete cost of $2.6 million. These results are not quite as good as we have reported in the last few quarters, primarily due to four wells we drilled on the [Sybil/Taylor] lease which in hindsight were too near the Muenster Arch, which inhibited permeability and reduced their initial rate.

Moving into the second quarter, we are back on track. Our first four wells we have turned inline this quarter have averaged 3 million cubic feet per day. We also benefited pretty significantly from our Barnett work over program. We are focusing on enhanced fluid lifting and well clean out and our operating teams were able to offset some of the weather and drilling issues. As an example, for this year we have increased gross production from 15 existing legacy well by a total of 5 million cubic feet per day for $1 million. We also increased our gross production on 15 wells by 8 million cubic feet per day in the new properties we acquired in the fourth quarter.

Moving forward for the remainder of the year, we are shifting our plan slightly. First, we are going to be drilling more five to six well tab size versus historically our three to four well tab size. This well had density increase should reduce our cost somewhat, but also will extend the time between turn inline. Second, we are working with offset operators to form new units to increase our lateral [lengths]. In some cases, we will be extending our laterals from 3000 feet or less to longer than 6000 feet, significantly increasing well recovery. In most cases, this reduces our working interest per well that really help the rate of return.

We are looking at a third rig later this year, gas prices and opportunities have presented themselves. Also, as our land work has extended our laterals, it has reduced somewhere our working interest so we have more capital available. This is another benefit of our scale on the Barnett. Like many of our assets, our Barnett performance shows that a lot of blocking and tackling helps keep things moving forward despite the ups and downs in my face.

Moving to the Austin Chalk, where EVEP has about 14% interest in the overall EnerVest asset base. There are two primarily activities driving the bus for EVEP. First, our conventional Austin Chalk program continues to create good result. This program focuses on drilling grass roots, multi stage horizontal wells and on re-entering old horizontal wells for multi stage fracs.

For 2014, we plan on drilling 12 wells and re-entering six to ten wells. This work is very repeatable on economics. So far this year, we have drilled four wells and re-entered four. On the wings of this work, production in the Chalk has increased somewhat currently this year. Perhaps the most significant activity in the Chalk area is the evaluation of the Northern Eagleford, which lies under a lot of EnerVest and EVEP’s acreage.

As a reminder, EVEP and EnerVest institutional partnerships control approximately 800,000 gross acres in the larger Chalk area. About half of which is in a 50-50 joint venture with Apache.

There are 19 rigs running in the play mostly in Brazos and Burleson counties, results from the early drilling in the play look encouraging. Halcon reported lastly that their first 15 wells had an initial 30-day average of approximately 600 barrels per day.

Apache reported several wells including the McCullough-Wineman which had an 860 foot lateral, an average 1455 barrels per day and their two Stasny-Porterfield wells, which were 5400 foot lateral and average 525 barrels per day over the first 30 day.

We continue to receive AFEs for further Eagle Ford delineation. Operators continue to refine drilling and completion methods similar to most new plays. More recent AFEs are ranging from the high side of a little under 10 million to the low side of 7.5 million for multi-pad well.

Those numbers appear to be trending downward. Based on our current pace, EnerVest and EVEP will participate in 40 to 50 wells this year including a well we plan to operate in Lee County later this summer. Generally EVEP’s interest in the drilling will be a little less than 7% based on our acreage allocation. In Total, EVEP has approximately 20,000 net acreage in the various windows of the play.

So in conclusion, we’re pleased with overall operations and believe we’re well-positioned as we moved towards mid year. Our Utica performance particularly the midstream is becoming more visible. Our operational effects have kept us in line with expectations and natural prices are strengthening.

With that, John back to you for follow up question.

John B. Walker

Thanks Mark. Telpin, we’re ready to take questions.

Question-and-Answer Session

Operator

Thanks you, sir. (Operator Instructions) Thank you. The first question comes from Kevin Smith from Raymond James. Please go ahead.

Kevin Smith - Raymond James

Yeah. Good morning, gentlemen.

John B. Walker

Good morning, Kevin.

Kevin Smith - Raymond James

Yeah. I just want to get your thought process. Does the UEO expansion plans -- does that impact potential Cardinal Gas monetization, maybe the timing of it?

John B. Walker

No.

Kevin Smith - Raymond James

Okay.

John B. Walker

There are really too – I mean they are very related into these – obviously we can’t process or fractionate UEO unless Cardinal gathers and compresses. But in terms of monetization there’ll be two separate events and I did mention that if we have tagged along right some above.

Kevin Smith - Raymond James

Did does this increase value then of Cardinal Gas?

John B. Walker

Does it increase the value? Well, I think what increases the value of Cardinal Gas is – I think that we’ve founded this Northern Central part of the wet gas window is holding up is the best part of the window. And as you move south, at least according to our calculations its about, if you get in Noble County there about 89% of that really turns out to be dry gas.

And so, UEO and Cardinal collectively are in the heart of the gas window. And the expansion for example with AEP probably does help Cardinal to a certain extent. But, I did believe the Chesapeake is playing down – continuing to drill 180 wells per year and that’s going to keep Cardinal very busy as we do that.

Mark A. Houser

Yeah, Kevin just expanding on John said, our projections for the well tie inns from Chesapeake really haven’t changed. We just have more commitment in terms volumes now from the Chesapeake Total EnerVest acreage. So again, it just really kind of walked it in more firmly but it’s the same work pattern we’d seen for Cardinal at this point.

John B. Walker

Yeah. Let me correct something, you were obviously not clear. The AEP 145,000 acreage gathering will be done by Momentum not Cardinal.

Kevin Smith - Raymond James

Okay. And then one more question if I may and I’ll jump off. When do you expect to be able to talk about volatile oil window, well results either operatef or not op?

Mark A. Houser

Kevin, as it was mentioned, I think everybody’s aware, EQT has slowed down some of their activities in oil window. On the other hand, Chesapeake, through our Total, Chesapeake, EnerVest joint venture, we have a well that we’ve drilled and completed the Parker well. They’re going to be bringing on line later this year, really later this summer within a few weeks I believe.

The information on that, when we’re able to announce that we’re really anticipate having some data on that, kind of around July and August window. And then we’re also planning on drilling some of our wells around that timeframe if well, our one or two wells we plan drilling this as we mentioned before. So, I’ll say it will be kind of third quarter-ish when we should start having some good data.

I will say on the Parker well they’ve change the frac design quite a bit. They’ve expanded the amount of sand we’re pumping in a pretty big way even relative to those most recent EQT wells which were pretty wells as well, so it will be interesting to see how that pans out.

Kevin Smith - Raymond James

And what county was that in, the Parker well?

Mark A. Houser

Parker well is in Stark.

Kevin Smith - Raymond James

Okay. Thank you very much.

Mark A. Houser

No. I’m kind of correct. It’s in kind of Western edge of the AMI in Brazos county part of that.

Kevin Smith - Raymond James

That’s all have. Thanks.

Operator

Thank you, Mr. Smith. The next question comes from John Ragozzino from the Company RBC Capital Markets. Please go ahead.

John Ragozzino - RBC Capital Markets

Hi. Good morning guys.

Mark A. Houser

Hi, good morning, John.

John Ragozzino - RBC Capital Markets

Can you give us quick update on the sales process in the wet gas acreage, is there anything specific that you can point here as causing a further delays in process?

John B. Walker

As I mentioned, we feel like that as we see the ramp up, its going to increase the interest and it has to certain extent. But when you have over 1000 pounds of back pressure and high fluid levels in each of these well bores as we had up until just few months ago, you really can accurately calculate what they are capable of doing. And we’re now seeing that it is encouraging, but we need to – we still got well over 200 wells that we haven’t been able to bring into the system, because we couldn’t process.

And so we’re going to approach it differently than we did in the past and that its going to be very focused on the Carroll, Columbia area and we feel like that expands the group that would be interested there, but it’s very high on our priority list, but we don’t want to go through another process, like we went through late in 2012 and early 2013. We’re trying to in accordance and working with Jeffreys. We’re trying to make sure that this is a very successful.

Now, obviously what we've sold in Harrison and Guernsey and Noble counties we got a very good price in our initial deal with AEP.

Mark A. Houser

John, the bottom line is as these wells get turned on line the acreage, and especially in Carroll county and adjacent counties is turning more into proved five acreage and we’re going to packaging it that way as we move forward.

John Ragozzino - RBC Capital Markets

Okay. That’s helpful. Thanks. And then can you just quick update on I guess, if you look at the bottom – the bottlenecking of the entire area, does that change you expectations for cash flow and production from override royalty interest?

Mark A. Houser

The key into the overriding royalty interest is some of the EnerVest acreage that’s in the market starting to get drilled out. We’re seeing some slight increases in the override. That’s when EnerVest is going to drive that bus as I said earlier. And again we’re starting to see more wells drilled around that and hopefully as we move forward in terms of the acreage sale and as then the new operator will accelerate that pretty dramatically.

Michael E. Mercer

Virtually all the acreage that we sold to AEP has a 7.5% override and as you’re aware AEP already has five rigs operating?

John Ragozzino - RBC Capital Markets

I'll let somebody else hop on. Thanks a lot guys.

Operator

Thank you Mr. Ragozzino. The next question comes from Michael [Gaiden] from the Company of Robert W. Baird. Please go ahead.

Unidentified Analyst

Good morning. Thanks for taking my question, gentlemen. Can I please ask Mike, would you update us on your thoughts about the balance sheet and how you see leverage progressing from here?

Michael E. Mercer

Yes. As you know, we are still, although we’re starting to wind down, still in the capital program on the midstream. We’ll have our final processing train and fractionation should be turned in sometime during the third quarter. So that’s going to start tailing off here pretty quickly. But -- so you should start seeing the increases and debt start to slow down here as we move through the year.

And on the other side of that, on the cash flow side, if you can see if you can see if you go back and look at the guidance that we put out with our fourth quarter earnings, you going to see a pretty good ramp-up in our midstream cash flows as we move through the year from this first quarter through the fourth quarter and continuing into ’15. So, we expect pretty significant increase in our quarterly EBITDA as based on the increase in midstream cash flows that should be coming as all of these trends get tied in and as volumes move up on the midstream side.

Mark A. Houser

And let me clarify something also and I think all of you know this. We don't like high debt levels. We don't like not having more than full coverage when we make distributions and so that something we’re addressing and hopefully we'll have it totally solved. But unlike almost any other company, we have all kinds of monetization options that the other people don’t have. And so whether that’s a midstream business, whether that’s sales of the Utica, whether it's the sale in the Eagle Ford, we’re not going to allow this to persist. And at the same time, I think that you’re seeing that we’re not going to do something stupid in terms of selling this very valuable acreage for less than what we really believe its worth. So we’re really at the point that I do think that this ramp up is going to help us particularly not only for the acreage sales, but its going to help us in terms of visibility of the midstream business.

Unidentified Analyst

Thanks for all that color. Can I ask then related to all that, do you gentlemen feel like you have both adequate liquidity as well as adequate headroom under your covenants to continue to deploy the capital into the midstream assets that do you see ahead of you inclusive of this new expansion of processing capacity?

Michael E. Mercer

Well on the expansion capacity, that’s primarily, that capital -- and as John said, we’re in the process of finalizing this specific timing and capital plans for the expansion and once we have all of that we’ll communicate in more detailed specific timing of capital requirements and the incremental cash flows that we expect off of that. But that incremental amount really for the expansion is really more ’15 and ’16, 2015 and 2016 capital versus this year. At which point we’ll have quite a bit more cash flow under our – from our midstream.

With regard to specifically the first part of a question on liquidity and financing capacity, we have -- at the end of the quarter we had about $550 million borrowed under our credit facility. The borrowing base is $730 million. And as I said, we expected the capital as we move through the year under midstream starts to slow down as we finish off these systems.

And we’re going to have increasing cash flow of the midstream so, but we will talk about that once we have like specific plans on the expansion. We’ll discuss that with – publicly with the market.

Unidentified Analyst

Great, thanks, Mike. I'd lastly ask, gentlemen, on the Barnett could you relate any additional color about what you’d need to see from the natural gas markets or other factors that would go into determining a few impact or you’re going to add three rig in the play? Thanks. That’s it from me.

Michael E. Mercer

Realistically we’ll be adding a third rig in the play for part of the year. The numbers we're seeing in terms of our returns based on our performance and based on gas prices, our attractive return. We said all along we -- our minimum hurdle rate is around 20% rate of return and we’re seeing more than that in our prospective wells. In particular we’re working to drill some wells in the acreage production that we brought in the fourth quarter where we had some wells that have potential of four to five Bcf – we’re trying to bring it online.

Mark A. Houser

Yeah, the average increase or acquisition, the average well and our estimates was 5.1 Bcf and that range is upto 9 or 10 Bcf. And so, a bit very economic and that’s why we’re going through the permitting process is slightly more complex than getting a straight permit you have to deal with all this municipalities. And that’s what has slowed us down a bit, that’s where we are going.

Michael E. Mercer

We have not planned on drilling originally any wells in 2014 in that area, but it looks now we will later in the year.

Unidentified Analyst

Thanks a lot guys.

Operator

Thank you, Mr. [Gaiden]. The next question comes from Abhi Sinha from the Company Wunderlich Securities. Please go ahead.

Abhishek Sinha

Hey good morning everybody. Quick question on the Barnett, just trying to get – I mean if you could provide some kind of color on the drilling operations segment of Barnett. So the four wells that you talked about whose results were not upto the mark, they were trying to think like what’s going on and I mean why couldn’t you see the first well coming as though it’s not going on to improve their operation or were they all put on pads and so you couldn’t get to know the results and if so is that the downturn of freezing pads and how do we think about that?

Mark A. Houser

Well the four wells that didn’t perform upto far, again we drilled too close to the Muenster Arch which is a geological feature. We’ve had seismic around and sometimes we have to do interpretation on how close you can get to something and the reservoir quality as you approach that Arch just wasn’t there. The rest of our wells are doing just fine. And again, from time to time when you are drilling two or three rig program possibly not all your wells are going to be upto see. We’ve made some great progress in our completion techniques, our landing techniques and feel really good about our opportunities going forward in the Barnett overall.

So it’s a plan to keep on giving as well and we would really do give credit to our operating teams on how they have managed not just the production operations, but also drilling, we’ve been able to get our cost per foot in terms of drilling, continuing to come down and our completion efficiency is getting better and we’re actually also bench marking our selves against some of the better operators in the play and our Total drilling complete basis are looking pretty good these days, so we feel very good about that play.

John B. Walker

Yeah and just to re-emphasize we’ve got a very large acreage position in Barnett and its purposeful. You know one of the last piece of EnerVest is when we move into an area is like or how or Michigan or the Barnett or right now in the Mid Continent we build concentrations for a lot or reasons. And the issue that we had in the first quarter was a very small part of acreage, a very small subset in that large acreage position.

Abhishek Sinha

Sure. And then could you just remind us what’s your number of potential bin locations left in Barnett?

Michael E. Mercer

Many, many years worth of locations we have I don’t have the numbers in front of me, but we have a ton of locations, we have you know 500 foot spacing we have some 250 foot spacing areas without the ton of [PUDs] in our new acquisition we did in the fourth quarter. So there is a very large inventory of that.

John B. Walker

I guess, I mean – I’ve seen coming with regards to this calculation that I think the most important thing is how many rigs are we going to operate and the key thing for us in drilling at a rate of return we back down on drilling any dry gas wells three years ago and we’re just starting to look at our best dry gas areas, not only the Barnett but other places so that we can exceed that 20% minimum rate of return that we have to just on capital.

Abhishek Sinha

Thank you. That’s all I have. Thank you very much.

Operator

Thank you, Mr. Sinha. This is the end of the Q&A. This concludes the conference call for today. Thank you for participating. You may now disconnect.

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Source: EV Energy Partners' (EVEP) CEO Mark Houser on Q1 2014 Results - Earnings Call Transcript

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