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

Q3 2011 Earnings Call

November 9, 2011 10:00 AM ET

Executives

John Walker – Chairman and CEO

Michael Mercer – SVP and CFO

Mark Houser – President and COO

Ronald Gajdica – SVP, Acquisitions

Analysts

Kevin Smith – Raymond James

Ethan Bellamy – Robert Baird

Dan Han – Morgan, Keegan & Company

Adam Leight – RBC Capital

Tommy Liam – Curry Partners

Michael Blum – Wells Fargo

Nick O’Grady – Plural Investments

Jed Theriac – George Weiss Associates

Dan Harhan – Morgan Keegan and Company

Operator

Welcome to the EV Energy Partners Third Quarter Earnings Conference Call. (Operator Instructions) At this time, I’d like to turn the conference over to Mr. John Walker, Chairman and CEO. Please go ahead.

John Walker

Okay. Thank you, Bell. I want to spend some time talking about our major developments from last week as well as some in the quarter. And Mark Houser, Mike Mercer and Ron Gajdica will address the most recent quarter, our financial information, operations and engineering.

For our investors and analysts’ of EVEP, I want to readdress some of the fundamentals about our company. We’re not a traditional E&P company that over-leverages and outspends its cash flow with myopic focus on production and reserve growth. Our focus and discipline areas are accretive acquisitions which we’re very good at, and building concentrated positions in basins to drive down cost. And that’s particularly important in the gas environment that we’re in.

We haven’t flip-flopped all over the place like some E&P companies, yesterday, a gas company, today, an NGL company, tomorrow an oil company. We manage EVEP to deliver increasing distributions and a high-rate of return over the long-term.

We forgo any capital activity that doesn’t deliver at least a 20% risk-adjusted rate of return which means that we’re not drilling very many dry gas wells because they can’t hit that target. Our acquisitions have historically been financed with 60% to 63% equity and cash flow and 37% to 40% debt resulting in debt-to-EBITDA ratio of 2:2.3:1 which is something that we plan to continue to do in the future.

The Utica is a phenomenal blessing and opportunity to add significant value to our unit price. But the above areas of focus and discipline have not and will not change. We’ve communicated all year to you that our goal in our acquisitions was to buy $500 million in accretive transactions in our areas of concentration, and we have accomplished this goal.

I very much enjoyed our negotiations on our Barnett deal with Encana. They’re people of high-integrity. They need capital for opportunities outside the Barnett. But we, however, expected to deliver over a 20% rate of return from that acquisition. The acquisition is around 25% liquids and 75% gas. We’re buying Encana at 7,400 per flowing Mcf and about $0.92 in the ground.

On top of those new attractive acquisition parameters, we believe that there’s several areas of cost reduction that we can accomplish. EVEP is acquiring $300 million to $325 million of this asset in the overall $975 million deal. We announced $300 million, we possibly could go as high as $325 million on that. In addition, EnerVest is acquiring a $233 million asset, EVEP’s part is $72 million, in the Barnett/Combo area. It’s around 40% oil and liquids and offers a high rate of return on the upside.

The approximately $70 million acquisition in the Mid-Continent offers some steady PDP, but great upside in the Cleveland Sands and Granite Wash. And in fact, we’ve already received our first two AFEs on that acquisition that closed last week. It’s a fill-in for other Mid-Continent acquisitions for the past two to three years.

We also dropped down from one of our institutional funds a $30 million asset with approximately 371 producing Knox wells and 520,000 gross acres in Ohio containing considerable Knox formation upside. There were no Utica rights transferred in this acquisition to EVET. And it’s important to note that we continue to see great acquisition opportunities in the market.

The announced and unannounced Utica results continue to be encouraging. I believe that Chesapeake announced its joint venture and part of the NGL window that establishes a new base level of value for the play. EVEP only holds 4,000 net acres in that portion of the JV with Chesapeake, but has about 23,500 net acres in that same area that are not part of the JV.

In hindsight, the original Chesapeake AMI was too large and insists a massive capital commitment unachievable in today’s world financial market. And we are very pleased with the job that Aubrey, Jefferies, and Chesapeake did in terms of establishing that base level for an NGL window.

I believe that it will take over 40 wells to precisely define the window of the Utica. As you would expect, the delineation wells that we’re drilling, to a certain extent, are science projects with a range of results, because we’re trying different completion techniques. Now that Chesapeake has announced its first JV in the Utica, EnerVest and EVEP will start the process of pursuing options. And I might add, all of these are positive ones.

I anticipate opening our data room late in the second quarter of 2012 or early in the third quarter of 2012. The options are to bring in a JV partner and for EnerVest to operate the acreage, to do an outright sell of our position or to do a tax-free exchange. I remind you that we have carved out a 7.5% override on all EVEP’s acreage.

While the large and preponderance of our acreage is in the NGL and oil windows, the information released to date is in the dry gas and the wet gas windows. I cannot comment on the specifics but I work with Chesapeake in the oil window has been encouraging. There’s a lot of work left to be done on the most effective completion techniques there. But it’s possible that the oil window will prove to be the most valuable unit asset that we own and we do have a considerable exposure in EVEP to that oil window.

Now I’d like to turn it over to Mike Mercer, who will talk about the financial results.

Michael Mercer

Thank you, John. For the third quarter adjusted EBITDA was $52.2 million which is a 40% increase over the third quarter of 2010 primarily due to acquisitions we completed last year and a 5% decrease versus the second quarter of 2011 which is primarily due to a decrease in crude oil sells volumes and an increase in LOE which was partially offset by an increase in natural gas and NGL volumes for the quarter.

Distributable cash flow for the third quarter was $30.8 million, a 28% increase over the third quarter of 2010 and a 7% decrease versus the second quarter of 2011. Distributions for the third quarter which would be paid next Monday, November 14, to holders of record as of November 7, were approximately – or will be approximately $29.5 million.

For the second quarter – or for the third quarter, production was 7.1 Bcf of natural gas – 7.1 Bcf natural gas, 207,000 barrels of crude oil and 285,000 barrels of natural gas liquids or 10.1 Bcfe. This is a 45% increase over the third quarter of 2010 production, a 7 BCF primarily due to our acquisitions we completed last year and essentially flat for the second quarter of 2011.

Third quarter net income was $87.8 million or $2.42 and $2.40 per unit per basic and diluted weighted-average LP outstanding. Several items I’d like to note, that were included in net income, were $68.8 million of noncash net unrealized gains on commodity and interest rate derivatives. This was primarily due to the decrease in future commodities prices that occurred from June 30 to September 30 of this year, and the effect of such decreased prices on the mark-to-market valuation of our outstanding commodity derivatives.

In addition, there was $1.3 million noncash realized loss on derivates related to derivatives acquired in conjunction with a 2010 property acquisition, and $2.7 million of noncash compensation-related costs contained in G&A as well as approximately $0.2 million of property acquisition due diligence and transaction-related costs.

We have also updated our guidance for the fourth quarter of this year which now includes for the period from the day of the closing or expected closing our recently-announced Mid-Con area, Ohio and Barnett Shale bolt-on acquisitions that were recently closed, and the two Barnett Shale acquisitions that we recently announced and that are expected to close prior to year-end.

Just a few notes on the guidance range, average daily production range is 117.7 Mcfe to 130.3 in Mcfe. We have appropriate price differential ranges and net transportation margins presented. Lease operating expense range is $19.8 million to $21.4 million for the fourth quarter. Production tax as a percentage of revenue are estimated in the range between 4.2% and 4.6%. And our cash G&A expense, excluding any acquisition-related due diligence and transactions costs, are expected to range between $5 million and $5.8 million.

We will be coming out over the next few months – sometime within the next few months with 2012 guidance estimates but are just now working through our budget process and working through our recently-announced acquisitions to formulate our plans for 2012.

We’ve also highlighted in a hedge table the natural gas and crude oil hedges that we entered into since our second quarter earnings release in August. I’d now like to turn it over to Mark Houser, to discuss our operations and results for the quarter.

Mark Houser

Thanks, Mike. If I were to describe our performance operationally this quarter, it would be average. No big surprises to the downside but no real surprises to the upside. We ended up on the low-end of our production guidance range, within the range on LOE, but we actually spent less – about 25% less than we anticipated on capital activities.

First, I’ll speak to capital, we about $19.2 million over the quarter. Most of this activity was in three of our four current active growth areas: the Barnett Shale, the Chalk and our non-activity in the Mid-Continent. We traveled back in our other growth areas, the Knox and Appalachia.

In the Barnett, we had two rigs active all year and continued on page to drill about 41 wells this year. We brought on 13 wells during the quarter, six in July and seven in September. We actually brought on another eight in October. So a lot of the third quarter activity should benefit us in the fourth quarter. Our drilling and completion guys are doing a good job of keeping costs as expected, averaging about $2 million to drill and complete each well. The wells IPs are ranging from about $1.7 to 2.7 million a day but on average, around our budgeted $2 million a day.

We are actually going down to one rig for part of November and December, but we’ll be back to two rigs, actually more than that with our other purchases early next year in the Barnett.

In the Austin Chalk we’re on pace to drill our targeted 18 wells during 2011. We brought on four wells during the quarter, one in late July and three in late September. We have brought on three more in October. So again, a lot of these wells really didn’t benefit the quarter but are strong now. Of the seven wells we brought online, five are multi-stage fracs. Combined, these five multi-stage wells, IPs at 1,600 and 1,800 barrels a day and $6.7 million a day. These multi-stage wells appear to have a flatter production profile than a lot of our typical non-frac Chalk wells and have good rates of return.

Our Non-TET activity in the Mid-Continent area is staying active. Much of this activity is in small chunks. But in total we’ll spend about $15 million this year participating in over 100 wells in the Kale Woodford, Toncolo Cottage Grove, and other zones in western Oklahoma and the Texas Panhandle. Most of this activity is with Sheridan in the Fifths Unit targeting the Viola.

We actually slowed down our activity in the Knox this quarter. Part of this slowdown was to adjust the leasing patterns in Ohio. We typically have to lease some small additional sections of land to finish up our Knox plays. That has become a bit more challenging with the Utica activity. We’re evaluating our new 120 square mile 3D size issue that is focused on the Knox and will provide a lot of drilling activity as we move into next year.

Now that we have the acreage position from our most recent acquisition in the Knox properties, we are re-prioritizing our Knox prospects and look to be very active next year.

Now I’ll move to production. Production was at the low end of our guidance range at 10.1 Bcfe, or about 110 million equivalents a day. And potentially flat with last quarter. The lower end of the guidance that we provided you all originally was premised on a more conservative thinking of completions and turn-in lines in the Barnett and Chalk. This is what came to pass, particularly in the Barnett. Our base PDP production actually performed as expected in general, although we had some higher-than-normal line pressures in the Barnett Shale and Appalachia and a few shut-ins in other areas. Our current quarter, with the benefit of the late third quarter wells, looks much better.

Just an example, line pressures in the Barnett around one of our gathering systems were about 118 psi in August and they’re about 142 in October. That’s a 20% increase in line pressure. We’re actually working with our – with Crosstex, our midstream folks to help bring these out over time and give us more capacity. And that’s really a common phenomenon for all operators, not just us in the basin.

If I look at LOE, we believe we’re doing a good job of keeping our controllables in line. We did show a slight increase quarter over quarter, but it was almost exclusively tied to NGL price-related gathering and processing expenses which moved with higher liquids prices.

Really, a couple of final comments, like most companies, we’re finalizing our 2012 plans, and as we go through the process, we’re benefiting from the increase of our scale, particularly in the Barnett. We anticipate better access to our key services, including pressure popping services.

We will provide a lot more details over the next two months, but generally, next year EnerVest expects to run about five rigs in the Barnett that includes the new acquisitions, one to two in the Chalk, two to four in the Knox, and an increased amount of activity in the Mid-Continent. Consistent with our philosophy, our activity will be intended to provide us with modest production growth through the drill bit and more significant growth through acquisitions. Our portfolio gives us the opportunity to do this. Depending on how things evolve with our Utica acreage, EnerVest also anticipates some activity on the EnerVest to operate a Utica acreage, which obviously will impact EVEP.

We’re also busy integrating our closed acquisitions and making plans on the integration of our other new acquisitions. Actually, since we are already in these areas, we anticipate these integration efforts to go reasonably smoothly.

And with that, I’ll turn it back over to John.

John Walker

Thanks, Mark. We’re ready for questions now.

Question-and-Answer Session

Operator

Thank you, sir. (Operator Instructions) And our first question comes from the line of Kevin Smith with Raymond James. Please go ahead.

Kevin Smith – Raymond James

Hi. Good morning, gentlemen.

John Walker

Good morning, Kevin.

Kevin Smith – Raymond James

A question on the Barnett/Encana transaction. Is that deal large enough that you’ll need to file audited statements, I guess similar to what you did last year with Tom?

John Walker

Yes, we will need to file an 8-K/A on that ultimately with audited financial statements we did with Talon last year.

Kevin Smith – Raymond James

Okay. I guess this question is for Mark. What’s your Barnett production look like on a sequential basis? I think last time it was up like 4% and is still turning higher and just not enough to offset from the other declines?

Mark Houser

Actually, Kevin, it’s trending a nice bit higher right now. In October, I mentioned, we brought on several wells in October in addition to some in September. It’s trended up a good bit. Of course we have a lot of those declines on those early wells out there. But generally on that basis we’re – we’ve been upwards.

Kevin Smith – Raymond James

Okay, great. Then my last question I think on your previous call you said you were going to spend roughly $10 million or so and Utica CapEx or at the end of the year. Is that still on pace and how’s that looking?

Mark Houser

Probably a bit slower than that, Kevin. Again, we’re still – most of the activity that’s de-risking the play – EVEP is not having us spend the money and we’re pushing it that way at this point. I would say that would be on the high side. We’re looking more to get more active next year and actually we’re meeting Friday next week to finalize a lot of those plans.

Kevin Smith – Raymond James

Gotcha. Do you think you’ll have well results based on those plans for the fourth quarter earnings call or is that more Q1 earnings call?

Mark Houser

I think Aubrey has said that – you’re talking about in terms of wells Utica or Chesapeake drills?

Kevin Smith – Raymond James

You guys drill.

Mark Houser

Well we’re not going to be drilling wells until next year, okay, in terms of our results. And I know Chesapeake has said that they’re planning on releasing their next results at year end as I recall.

Kevin Smith – Raymond James

Perfect. Thank you, gentlemen.

John Walker

Yeah. Let me explain one thing, Kevin. We’re really in two joint ventures. One joint venture that’s been announced with the unnamed foreign entity that’s in at least part of the NGO window and then outside that, we’re also in a joint venture with Chesapeake and we still have a carry on some of that. So any wells that either joint venture is not doing, you know, in which we’re being carried, we will drill some delineation wells that would enhance our position as we move in to the data rooms as I mentioned around the third quarter.

Kevin Smith – Raymond James

Perfect. Thank you.

Operator

Thank you and our next question comes from the line of Ethan Bellamy with Robert W. Baird. Please go ahead.

Ethan Bellamy – Robert Baird

John, the market obviously didn’t think much of Aubrey’s announcement and the way they handled the Utica JV. Did that change your thought process on timing for your own data room in the second quarter in terms of timing for the year? And did it change at all the level of interest you’ve received from third parties?

John Walker

Well, Ethan, you know I was an analyst for a long period of time and never really understood the market, and still don’t. So I’m not sure that you can ascertain from what the market saw in the JV or if they based it off something else in Chesapeake’s announcement. $15,000 per acre is an extremely good price for the NGL window. We think that, again, that it’s setting the base.

If we want to use an analogy, we’re right where the Eagle Ford was in 2008. Same number of permits, and if you want to look at trend lines, the trend lines in terms of price per acre have gone up enormously faster in the Utica than they did in the Eagle Ford. And we believe that they’ll continue to do so, because the results continue being encouraging.

So, I can’t predict what the market’s going to do. All I can do is look at results. And I don’t think that there’s anything that we’ve said that’s been promotional or inaccurate. We have had encouraging information. Now, I did say this morning that when you’re drilling these one-off delineation wells and you’re using different kinds of sands and different kinds of frac treatments and different, some of the times we’re using fluids, some of the times we’re using gas, they’re expensive to do this but you’ve got to learn how to treat these shale’s. And so, we do have a range of results.

In some instances, it’s worked fabulously where we have absolutely world-class wells. In some instances, we’ve had some wells that we’re probably going to have to go in and work over. And so, that’s what you expect in any delineation. But I also said that we’ll need probably about 40 wells to precisely define just the gas window, and we’re still defining the oil window.

Ethan Bellamy – Robert Baird

I appreciate that, John. Thanks. With respect to the oil window, it seems to me that that’s incrementally positive and different from what you guys have thought before, that the oil window might not have been as compelling. Can you provide any intel or data or anything you’re seeing, any context there for what might lead you to believe that’s a little more positive?

John Walker

Well, I said that, you know, we’re not the operator there, and I have to respect the fact that Chesapeake is the operator. And so, I do know results but I can’t release them. It’s their responsibility to release those. But I did say that the information is encouraging. So I don’t make statements like that without having a factual basis for it

Mark Houser

And just a bit anecdotally as well, but we’re seeing permits and we’re seeing announced activity and inquiries from some other operators, actually to the left of us on the western edge of what we see as the oily window. And it’s some pretty credible folks, so that tells me there’s a good bit of interest and some – and these guys don’t do it without some science too. So again, anecdotally it’s encouraging.

Ethan Bellamy – Robert Baird

Thanks, Mark. Switching to the Encana transaction, in the past you guys have shown an inclination to do a step change in your distribution when you’ve done a particularly accretive acquisition. Should we look for you guys to do that type of thing in your next distribution or maybe the one thereafter? Or should we expect continued, smaller distribution increases and higher coverage?

John Walker

I think we try to make a distribution decision every quarter, and of course with the Utica that’s caused some changes in terms of how we’ve been looking at things. Our objective is to grow the distribution a minimum of 5% per year. That’s a stated goal. We’re going to fall short of that this year, but I suspect that we will significantly exceed that next year and in the years to come.

Ethan Bellamy – Robert Baird

Okay. Thanks very much. Good luck.

Operator

Thank you. Our next question comes from the line of Dan Han with Morgan, Keegan & Company. Please go ahead.

Dan Han – Morgan, Keegan & Company

Good morning, gentlemen.

Mark Houser

Good morning.

John Walker

I was just wondering on the fourth quarter your production range guidance is approximately 10%. Mark, I was wondering if you could address what are the things that would cause it to vary to that degree, being a non-E&P guy.

Mark Houser

A lot of it is like I said about the third quarter, you have some timing issues when you’re bringing on new wells in the Barnett and Chalk places like that. You have some timing issues that you can control relative to when you get your wells fracked and when you get your wells brought on line. You have to connect them to a gathering system and then on into sales. Sometimes those things are done – they’re typically done in batches, and sometimes you’re right on in terms of that, but sometimes the person providing your services may be delayed on somebody else’s services, therefore yours take a little bit longer. So that’s why you’ll typically provide a range on things like that.

There’s also, again, and as we diversify it becomes less and less, but you have the gathering line increase, you have pipeline pressure increases. You have occasionally facilities that’ll have shutdowns you don’t anticipate. So there’s lots of different things that can interrupt operations. Again, as we try to diversify our portfolio, that tends to help us, but those issues nonetheless are still there.

John Walker

Dan, we’ve traditionally, if you look at our guidance over the years, we’ve tended to use kind of somewhere around the plus or minus 5% range.

Dan Han – Morgan, Keegan & Company

Okay. So that’s...

Mark Houser

For historical.

John Walker

Yeah. But I want to also mention the Barnett has become a larger part of our production, and we’re doing pad drilling. And when you’re doing pad drilling, at times you might drill two or three wells off a pad and then come in and frac all those wells later. And so there’s a time delay. And one of the things that Mark mentioned was that all of sudden we had a flurry of wells coming on in late September, early October, and as a result of doing that kind of work off of pads. And what he didn’t say is that we are using different completion techniques in the Barnett that seem to be working. And so, our results in some of those late September and early October wells are better.

Mark Houser

Just to that end, in terms of these, not surprises, but these changes in schedule, as we get more scale, we’ll have more predictable services. So we should be able to hone in on that better as we get a little bit bigger in the Barnett.

Dan Han – Morgan, Keegan & Company

All right. I appreciate that. On LOE expenses, quarter-over-quarter they jumped from $1.78 to the $1.91, and now with guidance, they’re going back to $1.81. So it went from $1.78, $1.91 to $1.81. What’s accounting for the big jump and why is it going back down?

John Walker

Some of it’s just timing of expenses and work-over. We also have, if you note in the fourth quarter, we’re adding new acquisitions which have different LOE levels as they filter into the quarter. So it’s just a mix of that. It’s not any one thing.

Mark Houser

It’s most – if it was any one thing, it’s going to be we’re adding some lower-cost reserves in as well in the Barnett.

Dan Han – Morgan, Keegan & Company

Okay. And I know for 2011 you had approximately $500 million acquisition goal. Do you have the same kind of goal for 2012 or?

John Walker

I think it’ll be approximately that. Obviously, the Utica is going to come into play big time on that. And so – but it is encouraging, the A&D market that we’re in right now versus the A&D market that we’re in for seven or eight months. We’re in a very active market. We’re seeing a lot of deals and it’s obvious by some of our acquisitions, we’re doing these very good PVs and so we’re pleased with the results.

Dan Han – Morgan, Keegan & Company

All right. Thank you, gentlemen.

Mark Houser

Thank you, Dan.

Operator

Thank you and our next question comes from the line of Adam Leight with RBC Capital Partners. Please, go ahead.

Adam Leight – RBC Capital

Good morning, gentlemen.

John Walker

Hey, Adam.

Adam Leight – RBC Capital

Just a follow-up on the Barnett. You’d talked about some issues with well communication and fracking last quarter, has that all been resolved or were some residual issues in this quarter?

Michael Mercer

You know, it’s interesting, Adam. Those are just residual issues period for Barnett producers. I was touring around two days ago in the new fields that were acquired from in Canada and talking to some of the operators. As folks crack wells in those areas, you do see an appearance. We’re seeing some of that. We’re getting some of our wells that came off back on.

As we keep active, we’re going to have some of that from time-to-time and as an example, in the Barnett, for the last month or two, we’re going to have one rig going instead of two to kind of fulfill our 41 well target for this year and as we reduce our activity of debt, we’re actually getting a bit of our old wells coming back online. So it’s really just kind of a process that actually talking to other folks with other companies. It’s the same type issue. So it’s something we manage and again, as you slow down in an area, you get that production back and we’re starting to see that.

Adam Leight – RBC Capital

Great. Then on completion costs there, are you seeing any price change per stage?

John Walker

You know, I’ve got that data right in front of me and our guys have done a wonderful job of keeping those basically flat. We’ve already been in discussion with several service providers next year. This last year as we accessed frac crews and pumping services, we were the new kid in town. But now we have a much more sizeable list of opportunities as affirmed and we’re getting a lot more interest and we anticipate, first of all, access to services to be good and second of all, we’re not seeing a whole of pressure on completion costs right now. That doesn’t mean that won’t change if folks decide to move in or out of the basins. But right now, it’s looking reasonable and we’re going to stick to around our kind of 2 to 2 total cost.

I guess the other thing I’ll comment on is our guys have done a wonderful job of reducing the number of days that it’s taking to drill these wells. It’s part of the reason we’re going back to one rig as we had a goal of 41 wells and we’re actually getting it done a little bit early.

Adam Leight – RBC Capital

Okay. Then, also on the Barnett, can you characterize the underlying decline rate now and how that might change with the acquisition?

John Walker

Well I think the ultimate decline rate, kind of the long-term PDP decline rate seems to be somewhere between 6% and there’s already been said it’s getting down to 5% in places. That remains to be seen. We’re kind of basing most of ours on 6%. You know, the kind of the current decline rate on assets depends on how much you’re drilling. Beyond that I think we’re more – if I recall kind of at a 10% overall decline right now with the new wells we’re bring on.

Michael Mercer

Yeah. On the PDP decline rate just a blow down, it’s over the next say two to three years it’s around 10% or 11% a year.

John Walker

Flattening over time.

Michael Mercer

And then it goes down, flattens down to 6% after that.

Adam Leight – RBC Capital

And do you have a significant inventory of uncompleted wells at this point? Or

Michael Mercer

No we don’t, actually. We have a few. We have I’d say a normal inventory. I think looking down we have maybe three right now that aren’t online so we’re doing a pretty good job in that regard. Now if you would have asked me on September 30th, we did. We had about eight or nine wells to bring on, so it ebbs and flows a bit.

John Walker

But one of the things, Adam, that I’ll point out and Mark can comment on this is we really do think that we can be more efficient than Encana. If we look at pumpers per well, if we look at their cost versus our cost we think there’s a significant difference. I mean I’m not talking about 5% or 10%. We think that there is a major difference that we didn’t incorporate into our economics that possibly we can change here on the Encana transaction.

Adam Leight – RBC Capital

I’ll leave that area alone with one more question. You’ve talked a little bit about activity in the Utica which curtailed your Knox development. Can you just clarify what you’re doing there?

Mark Houser

Well generally what I’ll tell you is when we’re doing Knox wells – we have a ton of Knox acreage and we have a lot of wells to drill. But inevitably there are little leases you need to acquire adjacent to your prospect to just tie up a small area and the ability to get that leased right now for at least a little while was somewhat problematic because all the guys were expecting super high numbers to simply get rights to drill a Knox.

And so to explain to a landowner look, this is not the Utica, this is the Knox, this is a separate deal – that sort of thing was just taking a bit more time. We’ve kind of got a system down now and again, with this additional acreage we’re really – we’ve really locked up a lot of the Knox. So that’s really the – that’s it, Adam.

John Walker

Yeah. We’re used to acquiring Knox acreage at $50 to $100 an acre and not several thousand dollars an acre and so we’re having to ask for a lease simply on the Knox rights.

Mark Houser

And Adam, I missed it earlier in my written comments, that we’re doing some more 3D seismic. And again, we’re kind of always enhancing some of our 3D. Our 3D has kind of given us some new ideas in the Know, and we’re giving our geophysicists all the time to kind of work through that and come up with, you know, again, we’re always looking to drill the best stuff until they’re kind of reprioritizing some things based on new data.

John Walker

Yeah. In talking about seismic, some of the seismic can be helpful for us in the Utica. We are a large group shoot with Chesapeake right now that we’re doing. We’re putting up 25% of the money. And at the same time, every time we drill the Knox well, we can at least do a sidewalk, or if not, a full barrel core in the Utica. So we’re learning something about the Utica as we drill Know wells in many instances.

Adam Leight – RBC Capital

Great. Thank you. That’s it for me.

Operator

Thank you. And our next question comes from the line of Tommy Liam with Curry Partners. Please go ahead.

Tommy Liam – Curry Partners

Thank you. I would assume in what you’re doing in Eagle Ford, you’ve got a lot of land down there. Is the deal with Apache still ongoing? And if so, what have they done over the last four years? And is this an asset that could at some point be monetized as a significant shale play to your company?

Michael Mercer

Well, EnerVest holds a million acres in the Chalk, and the source rock for that is the Eagle Ford. Apache a few years ago spent about $70 million drilling Eagle Ford wells. In the – and very little was drilled on our acreage, but in that little part, there was – the clay content was too high. But when you have a million acres, it really hasn’t been tested. The farm out there to Apache is 400,000 of our million acres. And there hasn’t been activity for a period of time, and I don’t anticipate any near-term activity.

John Walker

And EVEP share of that acreage is – averages about 13%, 14% of that total.

Tommy Liam – Curry Partners

Okay. Thank you.

Operator

Thank you. And our next question comes from the line of Michael Blum with Wells Fargo. Please go ahead.

Michael Blum – Wells Fargo

Thanks. Good morning. Just one...

John Walker

Good morning.

Michael Blum – Wells Fargo

Good morning. One, just one sort of conceptual question, and this is sort of excluding what’s going on in Utica right now. It seems like more of your acquisitions are more pads, slightly higher multiples of more the upside type development and less of the kind of traditional PDP mature properties. I’m just curious if you can just comment on how you’re thinking about the overall portfolio and what I’ll call the base business and the way you’re approaching the acquisitions. Has there been any kind of shift in your thinking and strategy?

John Walker

Michael, I don’t think that there’s been a shift in our objective or our strategy. It’s just that when you can buy world-class assets cheaply, we do that. We think that our PDP as an overall company right now is too low. It is a focus for Ron Gajdica in terms of our next few acquisitions really need to have a much larger component of PDP and I think that we feel comfortable as an organization if we’re more in the 80% to 85% range on PDP than where we are. Ron, do you have any?

Ronald Gajdica

Yeah, this is Ron. A further comment, in the Barnett sale, while you’re quite correct that we have a large flood component because of our Talon in Encana and other Barnett Shale acquisitions but having said that, the Barnett Shale PUDs have a low degree of risk to them. They’re not like your typical conventional PUD where you could actually have a dry-hole. There’s very little risk to these Barnett PUDs.

There is a bit of uncertainty but even that is being narrowed over time as more historical production is brought because of the mature state of the Barnett Shale base. So even though there is a PUD component and we want to get more PDP, we all agree with that, these Barnett PUDs specifically are not as risky as the normal PUD and analyst we think about.

Michael Blum – Wells Fargo

Great. Thank you very much.

Operator

Thank you.

John Walker

Thank you.

Operator

and our next question comes from the line of Nick O’Grady with Plural Investments. Please, go head.

Nick O’Grady – Plural Investments

Good morning, guys.

Michael Mercer

Hi, Nick.

Nick O’Grady – Plural Investments

Just a quick question in regards to the override. My questions is: it’s about 600,000 gross acres. Do you have any road map in terms of how many rigs you anticipate will be working on that acreage over the next couple of years just as we try to model it.

John Walker

Actually, we’ll know a lot more of that, I think, by year-end. We are expecting to get our first kind of view of our first AFEs in from our partner in some of this Chesapeake in terms of pace. Again, that’s for just a small amount of the acreage but we expect the drilling pace to pick up a lot. You know, beyond that, I mean Aubrey – Chesapeake has stated some of their plans for next year already and I think that’s a good proxy for what’s going to happen.

But I think a lot of that’s just to be determined at this point. As John mentioned, we’re very, very early in this process although the permit activity is kicking up overall in the Basin. So the answer, I think, is no, we don’t have a real good model but it’s always nice to have things that you don’t have to spend any money on to get revenue from.

Michael Mercer

I don’t have this in front of me, Nick, but if you look at the Eagle Ford in 2008, the cumulative permits were 26. Right now, through September, because I don’t have October numbers yet, I think cumulative permits were 31. But if you look at the Eagle Ford as of right now, it’s over 2,000 permits.

And so it really kicked up – Chesapeake is planning on adding 10 rigs per year. So, they’re planning on being 10 rigs by the end of this year. I think they’ll fall slightly short of that. But they plan of being 20 rigs by the end of next year and 10 rigs for year after that. And then there are a lot of others that have announced, including Anadarko, Devon, Exxon, Hess, that they will be drilling wells shortly, so – and we will ourselves. So the pace of activity is going to pick up. We’ve done a lot of modeling around here in terms of how many rigs, if we become the operator that we would be utilizing. And so it’s going, if you want to use a proxy, I think the proxy would be the Eagle Ford because it’s so similar to the Eagle Ford.

Nick O’Grady – Plural Investments

Got it. Thanks, guys. Appreciate it.

Operator

Thank you. And our next question comes from the line of Jed Theriac with George Weiss Associates. Please go ahead.

Jed Theriac – George Weiss Associates

Hi, John. Why wait until late Q2 or early Q3 to open a data room? And then, what would change that timeline?

John Walker

Well, again, we’ve – if you’re a crummy play or if you anticipate that the price of oil, liquids and gas are going to plunge, you’d want to do it today. But if you’re in a major successful play and you don’t think that, from these levels, that the price of oil and gas will go down, then we’ve done a lot of studies on this, and those that are patient tend to maximize what they get. And so, this isn’t, you know, it’s not something that we’re doing randomly. It’s something that we spend a lot of time studying and analyzing on how do you maximize the price that you get out of this. And we believe that our target there is appropriate.

Jed Theriac – George Weiss Associates

Okay, great. Thank you, guys.

Operator

Thank you. And our next question is a follow-up question from the line of Dan Harhan with Morgan Keegan and Company. Please go ahead.

Dan Harhan – Morgan Keegan and Company

Yeah, guys. One more question. I was wondering, on CapEx, how much would you characterize for 2012 being kind of organic growth versus just maintenance.

John Walker

We’re still working on that, Dan. I wish I could tell you a number. We, again, we typically said that our definition of maintenance capital is somewhere around the 20% to 30% of EBITDAX. So, you know, as to what we budget’s kind of above and beyond that. That’s to be determined. Actually, getting back to what Michael asked about our PDP versus non-PDP portfolio mix. One of the things we like about the deals we’ve done is almost everything we have is HVP. So we have the ability to increase or decrease activity on those leases as we choose, as it makes sense, as we meet our return hurdles and production goals. So we’re still literally in the middle of that budget process for right now.

Dan Harhan – Morgan Keegan and Company

All right. I sure appreciate it.

Operator

Thank you and once again, ladies and gentlemen, is there any additional questions? I turn the call back over to management.

John Walker

Well, thank you very much, Bell and thank all of you for joining us. We – if you have follow-up questions, please feel comfortable contacting us. Have a good day and a good fourth-coming quarter.

Operator

Thank you, ladies and gentlemen. This concludes today’s EV Energy Partners Third Quarter Earnings Conference Call. Thank you for your participation. You may now disconnect.

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