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

Q2 2011 Earnings Call

August 10, 2011 10:00 AM ET

Executives

John Walker – Chairman and CEO

Mike Mercer – CFO

Mark Houser – COO

Analysts

Kevin Smith – Raymond James

Ethan Bellamy – Robert W. Baird

Praneeth Satish – Wells Fargo

Bob Sohaney – RBC Capital Markets

Richard Roy – Citi

Kathryn Smith – Upstream Newspaper

Operator

Good morning ladies and gentlemen, thank you for standing by. Welcome to the EV Energy Partners’ Second Quarter Earnings Conference. During today’s presentation all parties will be in a listen-only mode. And following the presentation, the conference will be opened for questions. (Operator instructions) I would now like to turn the conference over to John Walker, Chairman and CEO. Please go ahead.

John Walker

Thank you, Douglas. Good morning everyone. I have with me the young 50 year-old Mark Houser, it’s his birthday today, who is our Chief Operating Officer; Mike Mercer, our Chief Financial Officer; and Ron Gajdica, who is in-charge of Engineering and Acquisitions.

The second quarter was a good one for EV Energy Partners as you can see based upon strong liquid prices and good cost control, our EBITDA was above the midpoint of guidance and distribution coverage continues to strengthen. Production fell within 2% of our guidance midpoint. Our Barnett production has grown albeit at a slightly slower pace due to the timing of bringing wells online, and Mark Houser is going to address that.

We slowed capital activity in our Knox area partly to respond the softening crisis and partly to reserve some capital for taking off some Utica drilling. Our big concern for quite a while about both gas prices and liquids prices for the remainder of the year. This is exasperated with the slowdown in the US economy. As I’ve stated before, we care much more about rates of return than production growth. So we’ll watch and adjust as we move forward this year and early next year.

And again as I’ve said before, we do not drill wells without a risk adjusted 20% rate of return. I remain optimistic that EVEP will participate in some very accretive acquisitions before year-end. The deal pipeline has not been a strong through the first half of this year but its strengthened recently, and we’re looking at several deals. As we always do, we will be patient in our acquisition efforts to reduce our risk of overpaying.

We have almost a 20 year history at EnerVest in the acquisition business. Our 37% compounded rate of return to our investors is based upon disciplined buying, building concentrated core positions such as in Ohio, exporting more reserves than in the original acquisition economics and driving down costs in all assets of development and production. The philosophy is the same for EVEP in the acquisition market as well.

While we have a stated goal in EVEP of $500 million of acquisitions this year, we’ll buy only if we buy right. This brings me to the Utica Shale. The EnerVest Group including EVEP has over 780,000 net acres and in excess of 1.2 million growth acres in Ohio. Our position was to establish primarily through a series of acquisitions over many years. Some of you if not most of you might be first time listeners and only are interested in my comments about the Utica and the aftermath of Aubrey McClendon’s Chesapeake earnings call and subsequent statements from the week before last.

Chesapeake has been our partner and a large part of the Utica play for over a year. Aubrey has been a friend of mine for a long time and I respect and admire his many accomplishments, particularly his focused and dominant players in all US major shale plays. In Utica, EnerVest has a large swath of acreage in which we are partners with Chesapeake. And Chesapeake operates that acreage. 40% of the EnerVest family’s acreage is in that joint venture.

Chesapeake has a data rim [ph] open currently to bring another partner into our joint venture. It also has considerable acreages, broker team has a symbol and we’re not a participant in that acreage. In addition, EnerVest has retained 414,000 net acres, their held-by-production which has very high working interest and are operated by EnerVest. Specifically EVEP has a 7.5% override and 240,000 net acres. And let me try to explain that because I understand I was out of town yesterday, moving my daughter to college and I understand we got several calls on that.

Our leases have been in place for many years, in fact decades and in some instances with a 12.5% royalty. In our first deal with Chesapeake that we closed July 1st of last year, we’ve already carved out a 7.5% override in that acreage and EVEP has a 7.5% override in 80,000 net acres. In the 414,000 acres, we carved out an override for EVEP and our Institutional Fund XI. And so EVEP has a 7.5% override and approximately 160,000 net acres.

Now we’re doing this as a result of having very high net leases. If you look at the Haynesville or the Eagle Ford, their royalty burden is 20% to 25% and more in many instances. Our royalty burden was 12.5%. So we’re delivering an 80% net lease which is much higher than the other plays in the major shale plays. And the reason that we wanted to do this is there are buyers of royalties and they pay two to three times more for overriding royalty interest than they do for working interest.

The other thing is if you look at this non-cost bearing override, it’s extremely valuable if you look at it on a net revenue basis. And in fact some of the smaller participants with 40,000, 50,000, 60,000 acres are 7.5% royalty and 240,000 acres is much more valuable than what they have in a working interest. EnerVest has 22,000 net acres in the Chesapeake partnership that I previously – I’m sorry, EVEP has 22,000 net acres in the Chesapeake partnerships that I previously mentioned. And it has 137,000 net acres in the EnerVest operated acreage.

The preponderance of data on the Utica gathered to-date has been shared by Chesapeake and EnerVest. EnerVest and its predecessor companies have drilled through and logged to Utica more than 600 times. We have numerous full barrel and several cores of the Utica in all parts of the producing regions of Ohio. However, Chesapeake has drilled in courts and wells that EnerVest does not have the access or right to that data. Aubrey’s comments were based upon more data than we have, specifically producing well results and in his comparisons with other basins are based upon more experienced and factual results than we have.

I can confidently say that the fundamentals of a major shale play are present in the Utica Shale. Technically, the evaluation work that we have performed independently utilizing both internal staff and outside consultants support what’s been set today. The comparisons to the Eagle Ford Shale appear to be accurate. In addition, we have many other favorable factors that are present in some shale plays. We’re located in a major population in manufacturing region of the country that needs low cost energy.

We’re located in a state that has many skilled but unemployed workers that we can employ. Our leases for the most part are not in urban areas, and we have very workable topography. The state has longest regulations, fair taxes and strong and supportive executive legislative and regulatory leadership. And I have and continue to meet with these leaders.

Yet we’re still in the early stages of completing and testing wells, only one well, Chesapeake’s 100% on BO [ph] well has any sustained production. Within 30 to 60 days Chesapeake and EnerVest should have six state wells completed and testing our inline producing. Our reports to you to be founded upon sustained production. Setting expectations are critical in my opinion. We know that we in Chesapeake are the two major players in the core of this major shale play. We also know that within the core we’ll have some outstanding wells and some for geological engineering reasons will be challenges.

Clearly outside the core, there will be mixed results. It’s our belief that the majority of EVEP’s acreage falls within the emerging core of this play. I caution all of you to be skeptical of reports and statements from sources or participants with limited factual data and I think most of our competitors have limited factual data. Besides Chesapeake and ourselves, we do not believe that any other companies have these physical factual results to correctly assess the Utica at this time.

Currently we’re optimistic about the Utica base from the widespread work that we’ve done with our partner Chesapeake, and our information to-date has been encouraging. We will report back to you when we obtain enough sustained production from a reasonable number of wells.

Now I’d like to turn it over to Mike who will discuss our financial results for the second quarter.

Mike Mercer

Thank you, John. For the second quarter, our adjusted EBITDA was $55.1 million, which is a 49% increase over the second quarter of last year and 9% sequential increase over the first quarter of 2011.

Distributable cash flow for the second quarter was $33.1 million, which is a 43% increase over the second quarter of 2010, and a 5% increase versus the first quarter of this year. I’d note that distributions for the second quarter which will be paid this Friday, August 12th to holders of record as of August 8 will be $29.5 million. Now the increases in adjusted EBITDA and distributable cash flow are primarily related to the acquisitions we completed during the second half of 2010 and as well somewhat to improve commodity pricing.

For the second quarter, production was 7 Bcf of natural gas, 241,000 barrels of crude oil and 272,000 barrels of natural gas liquids or 10.1 Bcfe. This is a 48% increase over the second quarter of last year, production of 6.8 Bcfe, primarily as I’ve mentioned related to acquisitions we completed during the second half of last year in both the Mid-Continent and Barnett Shale areas, and a 2% sequential increase over the first quarter’s 2011 production of 9.9 Bcf.

Our net income for the second quarter was $39.2 million, or $1.03 per unit. And I am going to note several items here within that net income that were included. As you know we have a lot of commodity price hedges that extend out significantly into the future. $17.4 million of non-cash net unrealized gains on commodity and interest rate derivatives were included in net income, primarily due to the decrease in future commodity prices that occurred from March 31st to June 30th and the effect of such decrease prices have on the mark-to-market evaluation of our outstanding derivatives that run into 2015. And in addition, there was $3.3 million of non-cash realized gains on derivatives related to term extensions through July 2015 that we’ve put into place on certain interest rate swaps into derivatives acquired in conjunction with our 2010 property acquisition.

We also had – I’d note $1.7 million of non-cash costs contained in G&A expense as well as approximately $200,000 of due diligence and transaction related costs in G&A related to acquisitions. In addition, we had a $5.1 million impairment charge relating to a recent divestiture that we did of a non-core oil property located in North Texas.

Now what I’d like to do is to turn it over to 50 year old Mark Houser to review our operating performance of this quarter.

Mark Houser

Thanks Mike and I’ll try to get through this without worrying myself out. Good morning everyone. John has given an overview and Mike has described our financial performance last quarter, so I’ll spend my time discussing our operational activities and capital plans for the second half of ‘011.

Overall we grew our equivalent gas production by 2% quarter-over-quarter and we were within our guidance range, and really pretty close to the median. Getting a bit more granular, our western division assets including the Austin Chalk and the Barnett increased by around 2% to 3% in the second quarter to net levels of 84.5 million today while our Appalachian asset essentially held flat at around 26.5 million today and we have slightly slowed our Knox activity as we build up our Utica plan.

We want to reiterate that EVEP’s overall goal overtime is to modestly grow production organically while leaving a dramatic growth to accretive acquisitions. We’re still requiring our 20% expected return on the capital project as John mentioned. That being said, our 2011 capital program is still expected to stay within the range of guidance we had provided previously. Our activity so far has been consistent with that level. The increase this year in capital as I’ve discussed before has been primarily to our new Barnett and Mid-Continent acquisitions.

About 75% of our total capital is drilling, about 14% is workovers and the balance is on land and sizing. About half of our drilling is occurring in the Barnett, and the Chalk and Mid-Continent, in the Barnett I am sorry, in the Austin Chalk and Mid-Continent areas each represent about 20%. That hasn’t changed with except – with perhaps one slight exception in Appalachia, we’ve slightly slowed our Knox program as we anticipate Utica activity should increase for EVEP late in the year.

Looking out at our Barnett, EVEP has a 31% interest in the properties. Production was up in the Barnett, about 4% quarter-over-quarter. We’re hitting our stride on drilling and are continuing to make modest adjustment to our completion activities. Starting March 13th, we’ve put a second rig in operations, also in the liquid-rich area and as of this week, we had drilled 26 wells and brought 18 online. We have four more wells scheduled to come online by the end of August and we now plan to drill around 40 to 45 wells by year-end.

Our biggest positive surprise in the Barnett has been our ability to keep both our operating expenses and capital costs down. This is helping us to continue generating over 50% expected returns on our new wells. We have now drilled more wells in the play in eight months than our predecessor did in 16 months. Drilling and completion costs have been maintained at about $2.1 million per well for the typical eight to 10 stage 3,200 to 3,500 foot long horizontal well.

Despite our increased activity, our direct lease operating expenses before marketing has declined quarter-by-quarter – quarter-to-quarter by about 6% to about $0.75 [ph] down in the Barnett. Our most significant negative surprise in the Barnett has been the amount of gas from adjacent wells that is being knocked off for three to four weeks when new wells in an area are frac. This phenomenon which I mentioned last quarter remains at any given time with our activity levels, we have approximately 3 million to 3.5 million today or little over 1 million day net to EVEP that is knocked off as we bring on new wells.

The impact on offset wells from large fracs is normal and will not impact reserves overtime but has impacted short-term production. To minimize this phenomenon, we are beginning to increase the number of frac stages to as many as 19 in our wells and reduce the amount of fluid pumps per stage. This helps us to maintain the frac areas but reduce the frac link to minimize impact on the offset and our earlier results on this are good.

Now moving to the Chalk, where EVEP has approximate 14% of its working interest in the field that’s operated by EnerVest. We continue to benefit from favorable liquids pricing and performance. We currently have a two rig drilling programs continuing both our naturally fractured horizontal program and our multi-stage frac program. We’ve drilled or reentered 14 wells so far in this year and on pace for about 20 this year.

Our most recent two wells which we’ve brought online both multi-stage frac, one in the A zone and one in the B zone have come on at a combined 825 barrels a day at 3.8 million today. Four additional wells are waiting on our pipeline. This Chalk asset in our portfolio has continued to be a great cash generator for EVEP for several years now. We’ve been spending about 30% to 40% of the EBITDA while production levels have remained essentially flat.

Looking at our Mid-Continent property, net production is running around 21.5 million a day in those areas, up slightly from the first quarter. We’re mostly in a non-op situation in these properties but the operating companies are active including Sanguine and Crest [ph] and are actively – which are actively developing the Granite Wash in the Texas, Panhandle where we have over 1,300 net acres 20 [ph] section. As a matter of fact I just signed another AFE yesterday and the PVs to EnerVest who has about quarter of these is very strong and range anywhere from $5 million to $10 million net to EnerVest, net to EVEP, I’m sorry.

But not only are they developing the Granite Wash, they are developing the Cottage Grove and Cleveland formations and what’s horizontal tests so far this year have added over 2 million today net to EVEP. Gas development has slowed in the non-op properties, although BP remains active in the Woodford. We’ve participated in some wells but that activity has been slowing down. Looking at our other properties, most of our other properties in areas of operating performance are performing essentially as expected.

Also Mike mentioned, we sold one property in North Texas for approximately $9 million and it did take a loss – an impairment on that. This was the highest cost property on our portfolio and really didn’t fit geographically or operationally for us so it was time to sell. Speaking briefly on Appalachia, our PDP production levels are performing generally as predicted and we are likely to keep production reasonably flat for the entire year, with generally limited drilling capital. Of course this assumes no Utica benefit this year which we don’t anticipate.

Our Knox activity this year started out with approximately 100 square miles of 3-D seismic across some of our acreage in Ohio that was purchased in the EXCO and Range transactions. We are beginning to evaluate this acreage and our encouraged of what we see. On a net basis we’re planning to drill about 10 wells for EVEP compared to only two last year when we were kicking off the program. However I want to point out that drilling has been delayed and reduced slightly for the year as we are not in a big hurry to drill these wells in the softening price environment, particularly when we anticipate some capital requirements this year related to our Utica position.

So generally to summarize, while we recognize the game change to potentially to Utica and we’re working very hard to further assess that potential, we continue to focus mostly on production cost surveillance while executing our development activities in the Barnett, the Chalk, the Mid-Continent and the Knox. Returns continue to be the driving force.

With that I’ll turn it back over to John.

John Walker

Thank you, Mark. We’re ready to take questions, Douglas.

Question-and-Answer Session

Operator

Thank you sir. We will now being the question and answer session. (Operator Instructions) Our first question is from the line of Kevin Smith with Raymond James. Please go ahead.

Kevin Smith – Raymond James

Hi, good morning.

John Walker

Good morning, Kevin.

Kevin Smith – Raymond James

Proud long time listener here and happy birthday Mark.

Mark Houser

Thank you.

Kevin Smith – Raymond James

I guess we got to hit it off, talking about the Utica. With the fact that portion of your Utica is with the JV – with Chesapeake’s JV. Do you have the ability to monetize your acreage position if Chesapeake brings in a JV partner at that point?

John Walker

Yes.

Kevin Smith – Raymond James

Okay. And then I guess the next question is now you’re participating in two to three wells…

John Walker

Yes, Kevin let me clarify my answer. I would anticipate that that partner would come in and buy maybe 25% of Chesapeake’s acreage and our acreage. So it would be a partial monetization, but it’s more than likely it would be a cash and carry monetization.

Kevin Smith – Raymond James

Okay, you would be able to do a full, or how’s that, I don’t know how that would work? I guess you probably could cut up the acreage position?

John Walker

We have a lot of options, all positive but within that joint venture, you ask with the party coming probably by year-end. It would probably be something on the order of 25% of our position in the Chesapeake joint venture.

Kevin Smith – Raymond James

Okay, so you won’t keep the same sort of monetization position that Chesapeake had (inaudible).

John Walker

On a relative basis, yes.

Kevin Smith – Raymond James

Got you. Okay, and then how much capital are you guys comfortable allocating or how much has already been allocated for the Utica with the two to three wells, and I guess what’s your comfort level there at the EVEP level?

Mark Houser

Projected for this year Kevin, and again this is a very dynamic estimate but we’ve really kind of set aside that’s our interest maybe $10 million that we might be spending late this year. That can move quite a bit depending on AFEs depending on timing. EnerVest including EVEP is actively permitting about 10 wells right now. Now the ones that we end up drilling remain to be seen based on the information we get back from some of Chesapeake’s activities and others.

So it’s still dynamic, but realistically for this year somewhere in that range as we said here in August seems realistic.

Kevin Smith – Raymond James

Got you. And then Mark, if I could chat one more question about the Barnett completion method, is that impacting your costs by drilling – putting more frac stages in it, and I guess what type of results are you seeing so far from that?

Mark Houser

Well so far the number two it seems really common in the Barnett play for us. It seems like on a reserved basis, we’re getting around 2 million – 2 Bcf equivalent. We’re spending around $2.1 million. And we’re coming on at rates that around two or little bit above 2 million a day initially. Of course these can decline pretty steeply, but so far our costs have stayed inline Kevin at around 2 million. Our drilling guys are doing a fantastic job in terms of being up our drilling activity and we’re able to use that savings we’re seeing there to offset a little bit higher costs.

We’re also pumping lower volumes on these fracs. And so we’re saving a little money there sometimes longer, obviously when you have a more stages, but we are pumping smaller volumes in that. So that’s helping us some there as well. So, so far it’s about the same.

Kevin Smith – Raymond James

Okay, great. Thank you very much and congrats on such a bright outlook for your company.

John Walker

Thank you.

Mark Houser

Thank you.

Operator

Our next question comes from the line of Ethan Bellamy with Baird Research. Please go ahead.

Ethan Bellamy – Robert W. Baird

Hi, guys couple of questions. First, what should we infer from the dropdown transaction that was intimated out in the 10-Q in terms of production and timing?

Mark Houser

Ethan, we’re in negotiations right now on a small dropdown. It will be for conventional production in an area that we operate in quite a bit. It will be reasonably small. And we’ll get back to you soon on that. Again that’s a negotiation that’s undertaken, so there is certainly uncertainty on it, but we feel somewhat certain that it will happen but there is still a lot of work to do to get it done. You will hear something about that over the next few weeks.

John Walker

It does not include Utica acreage.

Mark Houser

Yes.

Ethan Bellamy – Robert W. Baird

And Mark what was the production associated with the $9 million, the properties that were sold?

Mark Houser

I’ll get that for you right here, I have it in my notes. It was about 80 Boe per day net.

John Walker

Ethan, as Mark said it was geographically outside our operating area, but we also had some longer term concerns about the property. And so I think some people view an MLP as a portfolio, you just put things in and you never take them out. We view ourselves as portfolio managers, and once we’ve lived with the property for a while and we’re not pleased with the results, we have no problems of getting rid of it.

Ethan Bellamy – Robert W. Baird

Okay. I appreciate that John. With respect to the Granite Wash exposure that you mentioned Mark, can you tell me how many wells, what percentage and what kind of IPs and EURs you’d be expecting?

Mark Houser

Actually I can’t, based on the limited data we have. Again we’re in a non-op position in those, and so we kind of get data as it comes in. The primary operator in the Granite Wash that we’re involved with is Sanguine [ph] which is farm out from Chevron. And again Chevron takes over operator shift. Generally we’re looking at – the well so far in general are around 25% of our working interest. We’re looking at wells that we estimate are somewhere between 500,000 and million barrels of reserves on an eight inch basis. These typically cost around $7 million to $7.5 million that can move around a lot.

One of the wells came on recently around 750 barrels a day. So we’ve had some pretty strong wells. Again generally we have and some of the wells we’ve gotten identified recently. We have a quarter, but in some other wells that we’ve got AFEs on, we have a kind of a 3% interest. So and in terms of the number of wells, I think I mentioned there is 1,300 acre position in one area that doesn’t allow for lot of wells. They might allow for five or six over time depending on the space in the Granite Wash. So it’s something we’re trying to get our hands around more on which I have more specific answer but we are seeing good strong flow from those in terms of AFEs.

The one challenge there has been is that Sanguine drills, Chevron operates and Chevron is taking a pretty lengthy amount of time with some of the regulatory stuff they’ve put on it to get these wells online.

Ethan Bellamy – Robert W. Baird

What counties are those in, Mark?

Mark Houser

I can’t tell you right off, I can get back to you on that.

Ethan Bellamy – Robert W. Baird

Okay.

Mark Houser

I don’t know the answer.

Ethan Bellamy – Robert W. Baird

John, this might be a stupid question but I’ll ask it anyway. Where is the core in the Utica?

John Walker

Well as we drill more wells, and we’re trying to not drill just in the core, we’re trying to drill in the edges, core and even outside the core. We’re defining it more obviously our core test helped us with the one thing that you need in all these plays is you need to drill some laterals and make sure that it produces. So with that still being defined, but it’s a very large area and it encompasses several counties. And as I’ve said there is a lot of fringe players around the edges of the core and some that have picked up scattered acreage within the core, but Chesapeake and we really dominate the core of the play.

Ethan Bellamy – Robert W. Baird

Thanks very much. Good luck.

Operator

(Operator Instructions) And our next question is from the line of Praneeth Satish with Wells Fargo. Please go ahead.

Praneeth Satish – Wells Fargo

Hi, good morning. Just wondering if you could just talk a little bit more about the regulatory environment in Ohio, and whether you envision any obstacles there with respect to your Utica program?

John Walker

The regulatory environment as I said is very well established. Ohio in fact was selected as either number one or two state in terms of regulations by the Interstate Oil Compact Commission. And I think that that’s good. And I know when I have been in to see the Governor and the Head of the Senate and House and the Head of Department of Natural Resources, I’ve stated that it is important to us that regulations be strong and if we or anyone violates regulations, we think that severe penalties are appropriate. And so it’s good operating in a state that has long established regulations.

Now at the same time, we understand that regulatory environment would be by far the largest producer in Ohio. We produce 25% to 30% of the oil and gas in the state. And so we’ve operated under these regulations for a long period of time. And I think that you want stronger regulations, but you want people to be fair. And that’s what we’re experiencing in Ohio. Ohio has been hit hard by the loss of its manufacturing base. There are places that are very upsetting to go into as a result of the factories that have been idle for a long period of time. And we’re going to do our best to employ Ohio workers.

EnerVest itself has approximately 200 workers in Ohio right now based in Hartville outside of Canton.

Praneeth Satish – Wells Fargo

Okay, thanks. Second question is just wondering with commodity prices being volatile right now. Does that change your target for $500 million of acquisitions this year in 2012?

John Walker

Well obviously with lower prices, we’d like to buy a lot more. It’s just in the first half of the year we saw very little in terms of conventional gas and gas liquids deals of size. There were oil deals but they were selling at a very low PV. And we just don’t buy things at low PV. And because we don’t think that you can get a good return out of it. And so we know of some very large packages that we’ll be closing by year-end, and will be factoring those now.

Again, we – internally we develop the price that we’re willing to pay and if someone wants to pay more than that they win, and we lose. And so we can’t give you assurances that we’ll buy these things but we can tell you that we’re going to do our best to be competitive.

Praneeth Satish – Wells Fargo

That’d be great. Thank you.

Operator

Our next question comes from the line of Bob Sohaney [ph] with RBC Capital Markets. Please go ahead.

Bob Sohaney – RBC Capital Markets

Good morning guys. Just can you provide the CapEx breakup by region again? I missed that when you said that?

Mark Houser

CapEx breakout by region?

Bob Sohaney – RBC Capital Markets

Sorry, the allocation by region. The western region versus the…

Mark Houser

Yes, we’re – just in general terms we’re going to be spending about $65 million to $80 million, I believe that’s our guidance number. 75% of that is drilling, 14% on workovers. About half of our drilling is in the Barnett and about 20% is in the Chalk and Mid-Continent each. Okay, so that’s leaves the remainder basically one-seventh of capital in the east, six-seventh in the west in that ballpark.

John Walker

Yes, let me talk about this, I meant to come back to it based upon the previous questions. Bob, you’ve seen our map of our acreage in the Chesapeake joint venture acreage in Ohio. And that acreage is in close proximity to each other. And so there will be instances where we will form units with the Chesapeake joint venture and vice versa. Whoever has 50.1% will operate. But at the same time with Chesapeake likely to close the joint venture with a large carry, and so far Chesapeake has done quite a bit of drilling that EVEP has not participated in but several institutional partnerships have.

It is the de-risking the play. And I think that it’s smarter for us to be more of a participant in the Chesapeake joint venture than moving ahead at lightning fast pace on our 100% on acreage. And at the same time as you’re aware any time you have a major liquid supply, you have to have infrastructure in place that takes 18 to 24 months to put in. That process is ongoing currently and we’re spending a lot of time on that.

But at the same time, drilling wells right now and selling the liquids rich gas for Btu content and not getting the full value of that stream doesn’t make as much sense to me as may be doing a more timely drilling, where we get the maximum benefit from that. So that – of course that’s a struggle that you had in the Eagle Ford and struggle that we’ll have here, but we were probably tend to be a follower of the Chesapeake joint venture initially in drilling and not get ahead of that.

Bob Sohaney – RBC Capital Markets

Great. That’s it for me. Thanks.

Operator

Thank you. Our next question comes from the line of Richard Roy with Citi. Please go ahead. Our next question is from the line of Richard Roy with Citi. Please go ahead.

Richard Roy – Citi

Hello, can you hear me?

John Walker

Yes, Richard.

Richard Roy – Citi

Good morning. Mark, you mentioned that you’re spending about $10 million in CapEx in the Utica and that seems to be very dynamic at this space. Do you envision potentially the CapEx spending in Utica going to a point where you would have to significantly financing with debt or maybe even issue equity?

Mark Houser

What we’ve talked about in that Richard is that this will not be – this will be self funding by EVEP. We’ll look at all sorts of options overtime, but I’m sorry, this will not be a cash burden on EVEP that we will have capital available through various sources. We have all sorts of different options whether it be sale of some or all of the acreage overtime, whether it be joint ventures that sort of thing. So we see it – we’ll be positioned it as where it will be cash neutral or better for EVEP over the next while.

And again a lot of that especially as John has mentioned, most of this right now, kind of a de-risking is coming through the Chesapeake joint venture. And EVEP interest in that joint venture is small. And so a lot of the development for EVEP will be on the operated acreage of EnerVest that’s going to come a little bit later. So we’ve got a little bit more time of figure that out.

Richard Roy – Citi

Great. And just a follow-up, I believe if I remember correctly last quarter, John you mentioned that you wanted to wait so you have more detail on the Utica before reevaluating the distribution. Now that it seems like this is going to be a very profitable area for you. Have you revisited your thoughts on the distribution or you’re still on hold at this point?

John Walker

Obviously we made a decision not to accelerate our distribution this quarter. That will be payable next week. That’s something that we visit quarter-by-quarter. It’s great to have the opportunities to the Utica. But their capital demands and margins said that because of our business model, we’re never going to be in a negative cash flow position. And we’ve just got all kinds of terrific options. And so but one of those will not be borrowing money to finance our drilling in the Utica in any major way.

Mark Houser

Yes, just adding to that, John had mentioned in his statements, Richard, distribution coverage is getting better. It’s improving and that’s one of the things we wanted. On the other hand, the oil is at $80 right now. So we’ve got the Utica looking at it, so as John said its quarter-to-quarter.

John Walker

Yes, this is true for our fellow upstream MLP players, but we’re 90% hedged this year in terms of our PDP and so it really doesn’t have a great impact upon us what happens to the price of gas or oil. It only affects a small percentage of our production.

Richard Roy – Citi

Okay, thank you very much.

Operator

Thank you. Our next question comes from the line of Kathryn Smith [ph] with Upstream Newspaper. Please go ahead.

Kathryn Smith – Upstream Newspaper

Hi, good morning.

John Walker

Good morning.

Kathryn Smith – Upstream Newspaper

If you also just please walk me through briefly the history of the joint venture with Chesapeake, and I guess what has changed as of this latest earnings release? And can you identify yourself, please. I’m sorry I lost track of who’s who?

John Walker

I am sorry.

Mark Houser

To identify yourself.

John Walker

This is John Walker. We originally did a joint venture with Anschutz out of Denver for the Knox play in Ohio. And we retained – and that’s the EnerVest family, EVEP had very small exposure to that joint venture. And Chesapeake last year bought Anschutz close on that transaction September 30th. And we had some negotiations with Chesapeake that we signed in June in terms of how that joint venture would work relative to the Utica. And so it took us some time for us really to refine and define what role Chesapeake would have in that joint venture and what role we would have. And thinking about a 50 year partnership, we wanted to at least try to address a lot of the specifics about that which caused to take so much time.

It’s good that we’ve had such a long-term and favorable relationship with Chesapeake and so that allowed us to get into a quite a few details relative to that partnership. But in fact even before they bought out the Anschutz partnership, July 1st of last year, we did a smaller joint venture with Chesapeake owned some of the Westerly acreage in Ohio with them in which we retained a 25% interest. And in that particular situation, that’s where EVEP has the net 22,000 acres.

And we folded both of those together in the Chesapeake operated joint venture. Sorry, it was Anschutz coming together with a previous deal that we’ve done with Chesapeake.

Kathryn Smith – Upstream Newspaper

Okay. And I guess operationally, other than these different ownership stake operationally, who does what?

John Walker

Operationally, Chesapeake is in-charge of the joint venture. As we mentioned EVEP has 22,000 net acres in a 7.5% override and 80,000 net acres there. Obviously its exposure to growth acres is much larger than that. But Chesapeake does all the operations, the drilling completion. They are in-charge of gathering, marketing etcetera. So we are a partner with them. On the 414,000 net acres in the core of the play EnerVest operates that and that’s where EVEP has a much greater exposure, the 137,000 net acres and a 7.5% override and a 160,000 net acres in it, exposed really to much larger amount of acreage, but over 400,000 there, which is positive. And we have total control over drilling, completion, gathering, marketing, etcetera.

Kathryn Smith – Upstream Newspaper

Thank you.

John Walker

Douglas, we can take one more question and then I think we should wrap up.

Operator

Thank you. (Operator Instructions)

John Walker

Yes. I am sorry, Douglas.

Operator

Just one moment please.

John Walker

Okay. Well Douglas is not hearing any questions. I’m going to go ahead and wrap up. Obviously with Chesapeake’s announcement week before last, that was a major announcement based upon facts that Aubrey had in his disposal. And I think if you track Aubrey’s announcements on this plays, he has been pretty accurate in terms of what he said. And we based upon the information that we have, we can’t argue with what he has said. The Utica is obviously a blessing for us. Unlike other players in the Utica play, our position comes with all HBP acreage with great leases.

We have no time constrains in terms of where you have HBP. We’re not going to lose any acreage in our position. We received the Utica as a result of buying in the Clinton or the Knox in previous acquisitions. So we’re in a very advantageous position financially there. We’re in a very advantageous position by being in the heart of the play. And obviously this is very meaningful to EVEP into the whole EnerVest family in that it could double or more our assets assuming that everything proves out in the drilling.

And we look forward to sharing that information with you over the near-term. But I thank all of you for joining on our earnings call today.

Operator

Ladies and gentlemen, that does conclude our conference for today. I’d like to thank you for your participation. You may now disconnect.

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