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

Q1 2012 Earnings Call

May 9, 2012 4:30 PM ET

Executives

John Walker – Executive Chairman

Mike Mercer – SVP and CFO

Ron Gajdica – SVP, Acquisitions

Analysts

Kevin Smith – Raymond James

John Ragozzino – RBC Capital Markets

Ethan Bellamy – Robert W Baird

Bernie Colson – Global Hunter Securities

Tony Lingham – Macquarie Partners

Richard Roy – Citi

William Adams – GAMCO

Tom Wise – CenterPoint Properties

Operator

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the EV Energy Partners First Quarter Earnings Conference Call.

(Operator Instructions)

This conference is being recorded today, Wednesday, May 9, 2012.

I would now like to turn the conference over to Mr. John Walker, Executive Chairman. Please go ahead, sir.

John Walker

Thank you, Camille and welcome, everyone this afternoon. Thank you for joining us for the first quarter call for EVEP. Presenters this afternoon will be me, Mike Mercer and Ron Gajdica. Mark Houser, our CEO, is with his family at the funeral for his wife’s mother who had a courageous eight-year fight against cancer.

Relative to our production, revenues and distributable cash flow, we exceeded the midpoint of guidance. We fell short on LOE and G&A expenses because of some reclassification of expenses and non-recurring quarterly items, which Mike Mercer will address. Overall, it was another steady quarter for EVEP. Production into May continues to meet our forecast and I’m saying that because I want to spend just a little bit of time talking to you about the probable impact of the giant surplus of gas that has to be worked off by fall.

Unless we have an incredibly hot summer, and I want to remind you that last summer was 22% hotter than normal, it’s likely that sometime in the late summer, we will begin seeing much higher line pressures, the in mandatory curtailments, followed by rotating shut-ins of fields all over the country. EnerVest and EVEP have been exceeding – have been – I’m sorry – have been expecting this set of events since February when it was apparent that we were experiencing the warmest winter in recorded history.

Approximately 90% of EVEP’s expected production is this year and 80% next year, and I want to elaborate on that slightly in that really, 100% of our current production is hedged as well as our PDP for next year; it’s just that we continue to drill wells instead of some of those – the results from those PUDs are not hedged at this point. There’s no question, however, that all companies in the US with natural gas production will fall short of forecasts in the third and fourth quarters.

On a more optimistic note, and this is going to sound strange when you hear the title here, I’m giving a speech next week at Bentek’s BENPOSIUM titled, Why $1 Gas Prices Are Good For Our Industry. And I’ve spent a lot of time analyzing supply and demand in our industry and for the first time since 2007, I’m optimistic that natural gas supply and demand will start coming into balance in 2014 and beyond for a period. My work would suggest $5 gas prices in 2015 based upon demand strength and some supply constraints.

Turning back to EVEP, Ron will talk about the details of our operations, but I specifically want to address the Utica formation at the 10,000-foot level. The core of the wet-gas window is significantly de-risked and pad drilling has commenced or has been conducted by four wells on four pads now. Drilling and completion costs, on average have declined on Chesapeake-operated wells by over 30% this year. The condensate and NGL yields have noticeably improved and stabilized at higher levels from wells in which the frac water has dissipated into the formation.

In the oil window, we’re encouraged by the oil flows or tests from five wells. EnerVest has completed one well in Guernsey County and one in Stark County, about which Ron will discuss in just a few minutes. Both wells will be shut-in for a minimum of 30 to 60 days to dissipate the pads. And this is a procedure that we and Chesapeake are following and the results of these shut-ins in this dissipation process has proven to be significantly better – particularly in NGL wells, and we believe it will help in the oil window too.

We’ve hired Jefferies & Company to act as our advisor on the Utica monetization process and will formally launch the process by the end of the second quarter with a data room for our operated acreage opening in early July and we’re going to follow this with a data room for the outside operated leases opening about 30 to 45 days later.

Many companies have met with us informally, and some several times, and have expressed an interest in our large Utica position, particularly in the core of the NGL and oil windows. And so we’re encouraged by the interests that we’re seeing, and we are awaiting more information on the oil window before we open our data rooms in early July.

Now I’d like to turn over the discussion to Mike Mercer for our financial performance in the first quarter.

Mike Mercer

Thank you, John. For the first quarter of the year, adjusted EBITDA was $64.5 million, which is a 27% increase over the first quarter of 2011 and an 18% sequentially increase over the fourth quarter of last year. This is primarily due to the acquisitions that we completed and closed in the fourth quarter of 2011.

Distributable cash flow for the first quarter was $34.6 million. That’s a 10% increase over the first quarter of 2011 and a 12% sequential increase over the fourth quarter. Distributions for the first quarter, which are payable on May 15 to holders of record at the close of business on May 8, will be $33 million.

Production for the first quarter was 10.3 Bcf of natural gas, 285,000 barrels of crude and 423,000 barrels of natural gas liquids or 14.5 Bcfe. That’s a 47% increase over last year’s first quarter of 9.9 Bcfe and 30% sequential increase over the prior quarter. That’s primarily once again due to acquisitions we completed during the fourth quarter last year.

Our first quarter net income was $28.6 million or $0.69 per basic and diluted weighted average LP unit outstanding. Several items that I’d like to note that were included in net income were, number one, an $11.7 million unrealized gain on commodity and interest rate derivatives. This unrealized gain was due to the decrease in future natural gas and NGL prices that occurred from December 31 to March 31 of this year, partially offset by an increase in future crude prices, and the effect that the change in these prices have on the mark-to-market valuation of our outstanding derivatives.

We also had a $0.6 million of non-cash realized losses related to derivatives that have been acquired in the December 2010 acquisition settled during the quarter, and we also had related to recent acquisitions a $1.2 million or $0.08 per Mcf of production non-cash charge to our LOE that was related to oil and tanks purchased in connection with 2011 acquisitions that was sold during the first quarter. This is only a one-time item associated with those acquisitions. Excluding this amount, lease operating expense for the quarter would have been $1.89 per Mcfe of production.

Our lease operating expenses were a little higher than the midpoint of our guidance primarily due to the way we ended up on our GAAP classifying some of the expenses versus our estimates during the guidance process. GAAP primarily due to gathering and transportation costs on our production that were categorized – it had been categorized as LOE rather than a deduction on the revenue side from the production.

Other items to note for the quarter; we had $2.2 million of dry hole and exploration costs. This is primarily seismic related costs, primarily in the Utica and some in the Barnett Shale. A $0.6 million impairment charge related to non-core assets that we sold during the quarter. $0.6 million of non-cash deferred income taxes booked for the first quarter and $4.3 million of non-cash compensation-related costs that we typically have on a quarterly basis that is contained in G&A expense.

A couple of other items in G&A were $1.8 million of cash costs associated with the annual vesting of our phantom units. As you may know, every first quarter, we have a one-time per year vesting of our phantom units, and those occur during the first quarter of the year only. We also had $200,000 of property acquisition due diligence transaction-related costs that carried over from our acquisitions last year.

I would also like to note that during April, we completed our semi-annual borrowing base review, and our borrowing base was reaffirmed at $750 million. With the $470 million we raised in our first quarter common unit and senior notes offerings, which were used to repay bank debt incurred to initially finance our 2011 acquisitions, we currently have over $500 million of liquidity under our bank credit facility.

I’d now like to turn it over to Ron Gajdica for a review of our operations.

Ron Gajdica

Thank you, Mike. Good afternoon, everybody. For 2012, we continued to expect to spend approximately $160 million in upstream capital. First quarter expenditure of $29 million was lower than expected because of timing issues, but the full-year forecast remains intact. However, if declining natural gas prices dictate, we will slow down the rate of capital expenditures.

Most of our 2012 capital is for drilling. About 40% of our capital will go into the Barnett Shale drilling, where we’ll have three to four rigs running throughout the year, and can ramp that up as it makes sense, although we’re not planning on doing that at this point. About 20% of our capital will go into drilling the Mid-Continent for mostly non-op Granite Wash and Cleveland opportunities.

The remaining drilling capital will be spent in the Knox, Austin Chalk and Utica, including both our participation in the Chesapeake-Total joint venture and EVEP’s share of three to five Utica-operated wells. Again, as a reminder, on the Chesapeake-Total acreage, it’s small for EVEP and we do have a carry.

For acquisitions, we have not made any new acquisitions in the first quarter of 2012. However, we did execute a second and third closing on the Encana acquisition in the Barnett Shale for $36.5 million and also a second closing on the Trail Ridge acquisition, bringing the total acquisition expenditure to $42 million for the quarter. These subsequent closings were to acquire wells that had not been included in the original closing due to title defects, consents or other issues and these properties had been excluded from the year-end reserve report. We continue to evaluate acquisition opportunities as they materialize. For divestitures, EVEP along with EnerVest Institutional Funds sold its interest in the Brooklyn Field in the Austin Chalk. This netted $5.5 million for EVEP.

I will now comment on some of our producing areas. In the Barnett Shale, where EVEP holds an approximate 31% interest, we just completed our first full quarter, after closing the two acquisitions in December. Integration of the assets into our portfolio is going well and we are now drilling wells on the new properties. The additional production from the new wells is causing some line pressure issues, but we are making progress. Our first looping project reduced the back pressure and improved production by about 1 million cubic feet per day on part of our system.

We have several other looping and compression projects in the plan. We’re continuing to work with our midstream people to help bring these projects in overtime and give us more capacity.

We have three to four rigs working during the first quarter in the Barnett Shale and drilled 19 gross wells. We are currently running three rigs and plan to drill 91 gross wells during 2012. Our drilling and completion team continues to do a good job keeping costs as expected, averaging about $2.2 million to drill and complete most wells.

We continue to average about 10 days from spud to release, which is excellent performance. We’d like to see a bit better initial rates, but we are observing less decline than forecasted on these wells. We’re already applying some of our learnings from the drilling in the Barnett to our other drilling areas.

Now I’ll move to the Austin Chalk where EVEP holds a 13% to 15% working interest.

During the first quarter of 2012, we finished drilling one well and drilled a second well. Three new wells began producing during the quarter. We plan to drill nine wells in 2012. The multi-stage hydraulic fracturing process is working quite well in the Chalk. Our last two wells are producing above expectations.

One had initial production of 550 barrels of oil per day and the other had 6 million a day of gas with 130 barrels a day of oil. About half of the 2012 program in the Chalk will utilize the multi-stage process. And we are evaluating an opportunity to deploy this technology on more of our Austin Chalk acreage.

Our Mid-Continent area continues to benefit from our non-op opportunities. We participate in a large number of wells, about 40 in the first quarter, with working interests ranging from small overrides to over 30%. Drilling activity continues to be directed toward liquid-prone formation such as the Tonkawa, Cleveland and Granite wash.

Sanguine, Chevron and others remain active in the Texas panhandle with good results. And several of the wells we participated in during 2011 have already paid out, and we are seeing plans to drill offsets. Chesapeake is very active in the Tonkawa and Cleveland plays in western Oklahoma, and we anticipate that they will continue to drive development in the area which we will benefit from. Our team is evaluating as many as six or eight drilling opportunities in the Mid-Continent at any given time, and we continue to see some excellent capital investment opportunities.

Activity is slowing in the dry gas areas. However, this month we have seen first production from four Woodford Shale wells drilled by BP. Our net share of production from these wells is 1.3 million cubic feet per day based on BP’s early reports of up to 7 million cubic feet per day per well.

In Appalachia our conventional assets have been steady this past quarter. We’ve been recently encouraged by the results of our Knox program in Crawford County, Pennsylvania where wells have been exceeding our pre-drill expectations. In the Marcellus Shale in West Virginia, two wells on acreage we farmed out to PetroEdge are online and they’re producing about 1 million a day to our 7% net revenue interest. These are really strong wells and EVEP was carried on these wells.

Now let’s turn to the Utica. Our Utica acreage position in Ohio is about 150,000 net working interest acres. We also have the equivalent of a 2% average override on approximately 880,000 gross acres. Industry activity in the Utica continues to increase. To date, 193 horizontal wells have been permitted with the Ohio Department of Natural Resources. Production data from several wells in the wet-gas window have been released. The value of the gas, condensate and NGLs produced from these wells has demonstrated that the economics of the wet-gas window are quite strong and the play is viable.

I would like to discuss first the wet-gas window and then the oil window. Our joint venture with Chesapeake and Total is moving forward. Chesapeake is currently operating 7 rigs in the Utica and plans to operate 18 rigs by the end of the year, drilling wells for the JV in the liquids-rich area of the play. Total is paying a 60% carry on its 25% interest in these wells. The plan is for over 500 wells to be drilled by the end of 2014.

Drilling was initially focused in Carroll County, but is now spreading to other counties. Drilling times are improving as the industry gains more experience drilling in the Utica. Utica horizontal wells are now routinely being drilled in 21 days from spud to total depth, which is a significant improvement from last year.

Moving to the Utica oil window, first production was recently announced by Anadarko. Three wells in Noble and Guernsey Counties are now producing from the oil window. Also, at least one other operator has tested oil flow in the oil window, but has not made an announcement yet. EnerVest has completed its first operated Utica well, the RHDK #8H located in the oil window in Guernsey County. Please note that EVEP does not have an interest in the RHDK well. This well had a 3,400-foot lateral and a 13-stage completion.

With regard to operated wells in which EVEP owns an interest, we have drilled and completed the Frank #2H located in the oil window in Stark County, where EVEP has a 34% working interest. The Frank well has a 6,600-foot lateral, making it the second longest lateral in the Utica, behind the Hosey well. It was completed with a 24-stage frac, which is the most stages completed in the Point Pleasant yet.

Also, it was the first Utica well to utilize micro-seismic during the simulation process which indicated that significant amounts of shale were being stimulated in each stage and will provide important insights into the fracturing process as we continue to analyze the data. Both the RHDK and Frank wells are currently shut in for the dissipation period and are expected to begin producing by around the end of June. These recent results are very encouraging and support the viability of a Utica oil window.

We are now drilling the Carnes well in western Carroll County near what we believe is the wet-gas oil transition zone. EVEP has a 39% working interest in this well. We expect to complete this well during the second quarter, prior to shutting it in for a dissipation period. In addition, EnerVest is drilling a vertical stratigraphic test well in Ashtabula County and will take a whole core sample. This data will provide valuable insight into the area of the Utica where we believe the Point Pleasant member is not present.

Midstream infrastructure in the Utica play has begun. EVEP is participating in two Utica midstream companies. We have a 9% interest in Cardinal Gas Services, a company that provides low pressure gathering in the Chesapeake, EnerVest, Total JV area. We also have an 8% interest in Utica East Ohio Midstream, a company that was formed with momentum that will provide gas processing, NGL fractionation and pipeline connects for the JV production, as well as other production in the area.

The first wet-gas to be processed from the Utica will occur this December when the first train of the Dominion plant, located in Natrium, West Virginia, becomes operational. This will be followed in 2013 with the commissioning of several other Ohio gas plants, including those operated by Momentum and MarkWest.

As we previously mentioned, EnerVest is preparing for the sale or monetization of all or a portion of our acreage position this year. We have hired Jefferies as our investment banking advisor and are looking forward to working with a bank that has advised on most of the large US shale deals. We plan to formally launch the process by the end of the second quarter with the data room opening in early July.

We are encouraged by the interest we have been receiving from several potential buyers. We will consider joint ventures, swaps and/or outright cash sales. We hope to close the deal later this year. Phil DeLozier, our Head of Business Development for EnerVest and I are playing heroes in coordinating this process.

So far 2012 is playing out as expected and will be a very interesting year for EVEP. We’ll be continuing our efforts to modestly grow production in areas where we’re making a return on capital. We will be disciplined and if natural gas prices are too low, we will slow down our capital spending. We will remain diligent on cost control and continue to create value in the Utica. We look forward to the next several months as we should see additional Utica shale production and information and well results from a number of companies that are active in the play. While we focus on these areas we’ll also continue to look for good acquisitions particularly PDP oriented deals.

So with that, John, I’ll turn it back to you.

John Walker

Okay. Thanks, Ron. Camille, we’re ready for questions.

Question-and-Answer Session

Operator

Thank you, sir. Ladies and gentlemen, we’ll now begin 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 afternoon, gentlemen.

Ron Gajdica

Hey, Kevin.

Kevin Smith – Raymond James

Just two questions, I guess on the Utica and then one question on the Barnett if you don’t mind. Did you run a drill sim test on either one of these wells and is there anything you want to talk about from that perspective or from the log perspective?

Ron Gajdica

Kevin, we did not flow these wells. We’re letting them have their dissipation period at this point in time and they will not be flowed until later in the end of June.

John Walker

There’s no modeling on this right now. We’re in an area that we’re using something that works and eventually modeling will occur here and Ron as a PhD in petroleum engineering, could spend a good period of time talking about this.

But we’ve gone from flowing the wells immediately after they were completed and probably damaging the wells to a certain extent last year and we could explain that, but it probably would take too much time to flowing them for two or three or four days until we got initial hydrocarbons to now shutting them in immediately.

And Chesapeake has actually had some wells shut-in for over 100 days. So we don’t know whether it’s a 30-day shut-in, a 60-day et cetera, and we will be doing some on the same pad, we’ll be looking at opening up a well that’s been shut-in for 60 days and one that we’ll – have been shut-in for 120 days. But, what we’re trying to do is get the frac PUD away from the well bore.

Kevin Smith – Raymond James

Gotcha. And then how are you thinking about shut-ins as far as timing for these two wells? One’s going to be at 60 and one’s over 100?

John Walker

I think that these two wells, Ron said that they’ll be probably somewhere in the 45 to 60-day range.

Kevin Smith – Raymond James

Gotcha. Is there anything that you can do to monitor that, and say okay at this point? Or is it just a guess on the dates?

Ron Gajdica

Kevin, there’s a wide range of opinions about the mechanisms that are driving this dissipation process. Nobody really knows for sure. There’s no lab work to substantiate it. The reservoir models are not coded to allow modeling of this phenomena. So it’s really anyone’s guess at this point in time. It’s very early in understanding that process.

John Walker

It’s actually being used in established fields in the Eagle Ford as we’ve told you on many occasions, this looks a lot like the Eagle Ford. And in a field in the Eagle Ford where they were getting IPs of 400 barrels a day using the dissipation process, they almost doubled that. And so we believe that, that particularly with liquids in these nano-spaces that the capillary pressure of the formation, but we’ve got a certain advantage over the Eagle Ford in that water saturation there is about 20%. In the Utica, it’s 5% or less. And we believe that there’s clays in the Utica, which are not swelling, will be absorbing quite a bit of that water during that dissipation period.

Kevin Smith – Raymond James

Gotcha. And then one last question on the Barnett; what are we looking like with price sensitivity? I mean, do you have a floor that at this point in time you kind of slow down drilling if gas prices reach...?

John Walker

Ron will answer most of this, but again I want to remind folks that we don’t spend capital unless we can get a risk-adjusted 20% rate of return. In the Barnett, in general, we’ve got about 70% gas, 20% liquids in a lot of these plays. And in some instances, we’re testing that 20%. And we just want drilling. It’s a discipline that we stick to. Ron, do you have anything to add?

Ron Gajdica

Certainly. In our Talon acquisition in December of 2010 and our Encana acquisition in December 2011, most of the acreage is in an area of the Barnett where there are significant amounts of liquids – NGL liquids. There is a bit of it that is in a drier area. We’re obviously focusing our drilling activity on the liquids area, and those economics continue to be attractive, even at today’s commodity prices. In addition to that, in the acquisition in Montague and Wise County in the Barnett Combo play, those economics are looking very good too, buoyed by the high oil prices that exist today.

Kevin Smith – Raymond James

Gotcha. That’s all I have. Thank you.

John Walker

Thanks.

Operator

Your next question is from the line of John Ragozzino with RBC Capital Markets. Please go ahead.

John Ragozzino – RBC Capital Markets

Good afternoon, gentlemen.

John Walker

Hey, John.

Ron Gajdica

Hey, John.

John Ragozzino – RBC Capital Markets

Please send my condolences for the sad news that you shared at the beginning of the call, first of all. I was wanting to see if you could elaborate a little bit more on the Utica wells, specifically the Frank well and what the total costs on that was?

John Walker

I don’t think right now we’ll be releasing costs. I think that what Chesapeake has hit, and I don’t think that we disagree with this, is that we’re headed toward – from pad drilling we’re headed toward something on the order of $6.5 million. I can say that our Frank well was somewhat above that, but not a lot above that.

And, of course, the first well pays for all the gathering system that will be used for the whole pad. So we’re hitting, burning some of these early wells with the gathering lines. But I think our experience in the Barnett and other people’s experience in these other plays is, as you move from the science project and we’ve moved from that in the NGL or wet-gas window to pad drilling, we were satisfied that we have the completion technique on how to frac these wells.

We feel very comfortable about what we’re doing in terms of dissipation. And we’re driving costs down. And purposely I told you that our costs on the Chesapeake wells was down by a third from the average of last year. And we are on the Frank well, for example, with that long lateral, we’re pretty much on the average of where Chesapeake was but it’s still a little bit above that $6.5 million range.

John Ragozzino – RBC Capital Markets

Okay. Thanks. You mentioned there’s a shifting of activity from Carroll County. Can you elaborate on what counties are being increased activity levels?

John Walker

Well, to the north and to the south, Carroll County is the simple answer. If you look at most of the existing production and it’s coming from Carroll County. But the JV area extends both north and south from that so it’s going up into Stark and Columbiana to the north and to Harrison and Tuscarawas to the south.

Ron Gajdica

The reality is the reason for Carroll County is in the NGL window it’s probably the most important county. And as you move to the south you’re going to get less liquids, as you move to the east you’re going to get less liquids and we haven’t done as much drilling to the north. So that’s still going to be a bit of a science project.

John Ragozzino – RBC Capital Markets

All right. Thanks for all the offset detail. Just one big picture question; you mentioned rolling shut-ins in the summertime this year. What kind of aggregate curtailment numbers are you using for supply?

John Walker

Well, of course I’m not talking about just EnerVest, I’m talking about our whole industry. But clearly it’s dependent upon the type of summer that we have and having come off of two very warm summers, I don’t know if we just had a normal summer we’ve got to put away something on the order of about four Bcf a day of gas. And that’s pretty tough to do. And we’re running about two months ahead of where we’d normally be at this point in time.

John Ragozzino – RBC Capital Markets

All right. That’s all I got. Thanks very much, guys. I appreciate it.

Operator

Thank you. Our next question is from the line of Ethan Bellamy with Robert W Baird. Please go ahead.

Ethan Bellamy – Robert W Baird

John, the Paloma sale in the Eagle Ford (inaudible) the party looks to have been consummated at a pretty attractive acreage value. Is that a reasonable analog for what we could potentially see on the Utica monetization with maybe a smaller acreage value at a bigger number?

John Walker

We did go to the data room for Paloma. We were very interested. It was in the heart of the oil window. I don’t know that I can say that – we’ve chartered in all these fields – what the first per-acre price was paid, how that accelerated, where it went to. And the Utica is moving at a faster pace than the Eagle Ford. I think all of us with the KKR and Hilcorp at $21,000 thought that, that was a pretty darn good price. But – and I don’t know what you’re saying, per acre, we thought that that was in the $44,000 per acre range.

And clearly, the Eagle Ford’s about four years ahead of us. If you went back to 2008 or exactly where the Eagle Ford was in 2008/2009 and so we’ll see – we think that the best rock in the play is probably in Stark County and the great news for EnerVest and EVEP is that’s where we have a big concentrated position in the oil window. And I can tell you, we’re encouraged by what we’re seeing and not everything – it’s been announced and we’re not in a position to announce everything because we’re not the operator owned – some of the wells that we’re privy to in terms of test data.

Operator

Thank you. (Operator Instructions) Your next question is from the line of Bernie Colson with Global Hunter Securities. Please go ahead.

Bernie Colson – Global Hunter Securities

Hi, guys.

John Walker

Hi, Bernie.

Bernie Colson – Global Hunter Securities

Hey, I guess just kind of a big picture question for John. In your career have you experienced a situation where you have those kind of curtailments? And, I (inaudible) in the fall.

John Walker

I think that there was a period in the spring of 2002 and I don’t have that data in front of me that appear that we we’re coming out of the winter with too much gas. And basically what happens, Bernie, is that our wells become the storage field. And you can’t eat gas when storage is full and people keep trying to calculate, what is full storage? Well clearly, the last two years, it’s been 3.8 trillion cubic feet and probably full would be something in the 4.1 trillion, 4.2 trillion range, but you’ll never get storage full just because of the makeup of the storage fields and then you have cycling in the producing areas.

So the reality is if we fill in and we’re not going to keep on this pace; we’re not going to fill in August but we could be pretty close to being full in September. Then there’s no option except that the kind of description that I had that there’s going to be some rolling situation of curtailments. Firm transportation helps. And so that’s one of the things that we’ve looked at. But there’s not a lot of good that’s going to happen.

And the reason I made the comments that I did was that I think you should just anticipate that for everyone. It’s not for EnerVest or EVEP it’s for everyone because of – when you have a very traumatic event, the warmest winter in recorded history going back to the late 1800s, then it has a big impact when you come out of that period with 900 Bcf of gas. And so I do think that we could see some very low prices in September and October. And I do think that helps our industry.

I think that we needed something dramatic to get these guys that are drilling wells to hold acreage and drilling wells to just drill wells for production, despite the fact that they lose money on it. They’ve stopped or they’re stopping. And I think that that’s going to place limits on supply. Yes we’re going to get supply associated with natural gas liquids processing and associated with oil.

But that’s more like a 0.5 Bcf to 1 Bcf per year, not 5 Bcf per year. And at the point in time that we do get $4 or $5 gas prices, and we want to move those rigs to drill in some dry gas areas, those rigs are not going to be available, assuming that NGL and oil prices remain attractive. So that, in my opinion, is going to be a constraint on supply.

Bernie Colson – Global Hunter Securities

Okay. And just a follow-up; are there any – sort of the hedges that you have in place? How are the hedges impacted if you’re basically not able to get the gas out of the ground in effect? What do you do?

Mike Mercer

They’re financial hedges, and they are. Our oil hedges on average are probably right around the money, a little bit, maybe a little bit out of the money. But on the gas side, they’re all in the money. So we’d be collecting on that. I don’t think I would expect that we would probably have enough of a decline to where we would eat through that and go to an over-hedge position. But if we did, we would have financial hedges that might exceed production for a short period of time.

John Walker

Yes. We don’t have physical hedges. And so we would anticipate on the gas side, which we’re really talking about, that we will be paid. And this will all be resolved with hopefully a normal or colder than normal winter. I’m told that we’re moving into El Niño effect which should help some.

Bernie Colson – Global Hunter Securities

All right. That’s all from me. Thanks.

Operator

Thank you. Our next question is from the line of Tony Lingham with Macquarie Partners Please go ahead.

Tony Lingham – Macquarie Partners

Thank you. Regarding Utica you have said in the past that you thought you would have a deal let’s say signed before the end of the third quarter and closed before the end of the year. Is that still what you’re thinking?

John Walker

No. I’ve never said that. I’ve said that in the past that we thought that we would open our data room in the second quarter or late in the second quarter, but the only thing in terms of closing that I’ve said is we’d closed by the end of the year.

Tony Lingham – Macquarie Partners

Okay

John Walker

And so we’re on schedule in terms of where we expect to be. The dissipation process does take some time and I’ve never found that if you’re trying to maximize price, you get your maximized price by waving your arms. I think you need hard data from the oil window and that’s what we’re waiting on.

And so the Chesapeake wells, the CNX wells, the Anadarko wells and we’re participating with Devon, Anadarko and others in wells ourselves Sierra. And then our wells – we’re going to have hard data and we’ve got sharing arrangements with these other companies. We’re providing them data. RHDK as well as the Frank wells and then of course we’ve got some coring and log data that no one else has. So we’re in a good position to offer data to get information from their wells.

Tony Lingham – Macquarie Partners

Thank you.

Operator

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

Richard Roy – Citi

Good afternoon. I just have a question as it relates to the monetization of the Utica. Obviously year mentioned the prepared comments that wet-gas windows that you risk and you’re obviously working on the oil window. Now do you see a situation where you potentially do a deal – separate deals for the wet-gas window and separately for the oil window or you’re just looking at selling the entire position at once?

Ron Gajdica

Well, our discussions with our investment bank advisor are currently talking about packaging for our acres position, but having said that I don’t anticipate we’re going to be splitting it up between the wet-gas and oil. When you look at the map there are certain logical areas that makes sense that you cluster into sub-packages that way. But I don’t see us discriminating by window.

John Walker

The only reason that we, Richard, that we might sub-package is we’ve got – for EnerVest overall, we have so much acreage and our expectations are high and there’s not a lot of companies that could meet that expectation. We’re not going to sell it if we don’t meet our expectations.

Richard Roy – Citi

Great. That’s all I have. Thank you.

Operator

Thank you. Our next question is from the line of William Adams from GAMCO. Please go ahead.

William Adams – GAMCO

Yes, hey guys. A couple of questions. First, on the G&A expenses, are you guys going to be – are you guys still comfortable with the guidance you gave back in the fourth quarter release for the quarterly breakdown for the remainder of the year?

Mike Mercer

Yes. In fact, if you notice on our guidance the first quarter, it was a bit higher than the second, third and fourth quarter, and that was because we were estimating the effect of the cost of the vesting of our phantom units, which occurs during the first quarter once a year. It ended up – the G&A, we had a couple hundred thousand dollars for due diligence cost, which we don’t project. I think our cash G&A was about $7.8 million. A couple of hundred thousand of due diligence costs, and then our estimate of the cash cost in the phantom units was, actually, it – for guidance, the mid-point was a couple hundred thousand low. I think our guidance midpoint, if I remember, was about $7.35 million to $7.4 million. But we do expect it to come off in the second through fourth quarter simply because the amount that we had in the first quarter for the vesting of those phantom units that cash cost of that vesting was about $1.8 million and that’s a first quarter only item.

John Walker

Yes, Bill, since I don’t draw a salary, you can’t get much from me there, but Mike is very vulnerable here if we don’t hit our G&A target.

William Adams – GAMCO

Okay. Well I’m sure you’ll hit them. Then your maintenance spending, was that in line with your expectations and what’s your thoughts there for the rest of the year?

Mike Mercer

Well our estimated maintenance capital that we deduct, our calculation for estimated maintenance capital, it’s not specific wells as we’ve discussed before. It’s an estimate of which would be required on an average over time, in our current environment to maintain reserves and production.

And, yet we don’t do a forecast of that, simply because we determine it every quarter as we’re rolling forward through the year. But it’s been running, it’s actually between 25% and 29% of EBITDA, it’s been running about $1.25 per Mcf of production. And for the quarter, in recent quarters. And unless the environment changes, I wouldn’t expect big changes from those kind of levels.

William Adams – GAMCO

Okay. And then, I noticed on your cash flow statement you had about a $5 million proceed, $5.5 proceed from asset sales. I wondered if I could get a little more color on what those were. And were those...?

Mike Mercer

Yes. As, Ron mentioned, that was the sale of the Brooklyn Field in the Austin Chalk and our share of those proceeds.

Ron Gajdica

Yes. It was an area of – basically the Brooklyn Field we just saw limited upside. And our operations guys encouraged us to go ahead and sell that and it had a fair amount of liquids in it. And so we felt like with oil and liquids at a pretty good price, it was a good time to do that since we had a limitation there. And the Brooklyn field was an old, old from ARCO that, of course, BP took over. And we were limited to the Austin Chalk so we didn’t have anything uphold or downhold there. And so we just felt like it was a good time to get rid of it.

William Adams – GAMCO

Okay. Now just to clarify, was that included in your Bcf number then that $5 million, $5.5 million?

Mike Mercer

No. We don’t include gains on sales or anything like that in a distributable cash flow number.

William Adams – GAMCO

Okay. Other companies include proceeds from asset sales in their distributable cash flow.

Mike Mercer

Yes.

William Adams – GAMCO

Okay. And then, John, just maybe give us a little more color, since it sounds like you’ve done a lot of work before this presentation you’re giving next week, where is the inflection point in drug gas prices? Do you think is it next year or is it more back-end loaded than that?

John Walker

Well, I think next year is still going to be a pretty tough year unless we have a cold winter. We’re going to obviously go into the winter with storage as full as it’s ever been probably. And so I would anticipate that we’ll start seeing a better future for gas in 2014. But a lot of good things happened in 2015 in terms of the first LNG exports. And I think the hidden thing here is the petrochemical complex and steel, et cetera, the whole industrial use of gas, and hopefully we’ll see some coal plants shut down. At some point, probably about $3 to $3.50 in gas prices, you’ll have a shift that would occur to gas to coal. And therefore, we would lose, say 3 Bcf that we’re benefiting from right now is the utilities go back to using coal as the price of gas goes up. So that would only be offset by shutting coal plants down.

William Adams – GAMCO

Okay. And what kind of assumptions do you think – or how low do you think the rig count will go? We’ve seen a big drop. I mean how much lower can it go to react to the way that you think the industry is going to evolve over the next year or two?

Ron Gajdica

Well, of course everybody’s using different rig counts now. I of course grew up using the Hughes Tool rig count and I still use it. But probably something in the order of 500 for the gas rig count but the rig count when I was an analyst in Wall Street, you could predict a lot more things of off it but with the higher efficiency of horizontal rigs it’s not just the rig count. It’s the efficiency that you’re realizing out there and that makes forecasting all of this a lot more difficult.

William Adams – GAMCO

Great. Thanks for your comments.

Ron Gajdica

Thank you, Bill.

Operator

Thank you. And our next question is from the line of Tom Wise with CenterPoint Properties. Please go ahead.

Tom Wise – CenterPoint Properties

Yes. Another question on the upcoming Utica monetization; you mentioned the Stark County acreage as being very high expectation. I’m wondering if you can comment or elaborate on your Ashtabula acreage. In light of your comment that the Point Pleasant is not in existence there. Is that less marketable?

Ron Gajdica

The best part of the Utica Shale is actually the Point Pleasant sub member which lies stratigraphically directly below the Utica Shale. And usually when we refer to the Utica Shale in general, we include the Point Pleasant as part of the Utica Shale generally. The Utica Shale is aerially very extensive it’s going north into Canada it’s going east all the way to the Atlantic seaboard it underlies a large part of the Marcellus, the stratigraphic equivalent in the state of Michigan as the Collingwood Shale. So the Utica Shale itself is very extensive.

The Point Pleasant member right below the Utica Shale’s pretty much constrained to Eastern Ohio. The Point Pleasant has superior rock properties, lower clay content. It’s more brittle. It fracks better and that is the focus of the existing Utica development and I say that in terms of Utica in general. The Point Pleasant is the focus.

As we get in the Ashtabula County in the northern part of Eastern Ohio is going to be very interesting because the Point Pleasant is either entirely absent or barely present, but the bigness of the Utica is very thick. It’s one of the thickest places anywhere where the Utica exists. And so it’s going to be a very interesting development result when we actually get some wells into the Utica in Ashtabula County and see how it produces. The rock properties won’t be as good as the Point Pleasant, but the thickness is very good. So there is certainly some potential up there. But it’s a bit more risky in the sense that it hasn’t been drilled yet.

Mike Mercer

And so we’ve actually started that process of coring that well. And, of course, it takes you a little bit of time to get the core results back. But – and really, the other part of your question is will this be part of the sale. Again I’ve found out that by doing a lot of transactions over time, people usually don’t pay very much for arm waving. You need hard results. And I don’t think we’ll have the hard results in Ashtabula County to include it in the sale.

Tom Wise – CenterPoint Properties

But that would be at some later date then?

Mike Mercer

It would be.

Tom Wise – CenterPoint Properties

I had looked at a map of your acreage concentration in Ashtabula and specifically the location of your test well there. And do you see the world differently than the ODNR? They also publish maps and show Point Pleasant limit being well to the northern part of the county. Have your findings been different from what ODNR is publishing?

John Walker

We actually think that ODNR has done a pretty good job. But we think that we have a lot more data than they do. We’ve got a lot more cores that they don’t have. They don’t have, they do have some of the information from the cores, but they don’t have the cores themselves. And we’ve got a lot more penetrations of the Utica than they have.

And so we think that they’ve done a great job with the information that they have. We feel like that our information and I’m using our to refer to ourselves in Chesapeake because we’ve shared most of our data with Chesapeake. And so, we think it’s better than the geologists at the Ohio Department of Natural Resources. And we think they do an excellent job with the information they have.

Tom Wise – CenterPoint Properties

One last question, if I can. If we’re in a say, the oil window given an equivalent depth and equivalent thickness in the Point Pleasant, is it safe to assume that you can extrapolate and assume acreage values would be roughly the same at those same depths and thicknesses?

Ron Gajdica

It’s difficult to say what the market is going to put on acreage. In terms of valuing the acreage everybody’s geologic interpretation is different. Generally speaking, where you have hard production data to back up the economic evaluation, it will be risked less and therefore paid more and when you get away from production data it will get risked a little harder. How much harder is difficult to say and every company will be different and we just have to test the market to see how that will play out.

Tom Wise – CenterPoint Properties

Okay. Thank you. Best of luck.

John Walker

Thank you.

Operator

Thank you. And our final question is a follow-up from the line of Ethan Bellamy with Robert W. Baird. Please go ahead.

Ethan Bellamy – Robert W Baird

John, Chesapeake has had some bad press lately. Just for the record have you seen, heard or experienced anything on the fundamental side that would suggest they’re backing off or in any way not pushing the ball forward in Ohio that would be negative for EVEP holders?

John Walker

Have they had bad press lately, Ethan?

Ethan Bellamy – Robert W Baird

A little bit.

John Walker

Obviously, we have agreements with Chesapeake in place that take care of all kinds of situations and so we have a pretty comfortable feeling on where we are relative to agreements. The advantage that we have in our relationship with Total is that they’re providing a 60% carry in the NGL window and that’s where the bulk of the drilling with Chesapeake is occurring. And so Chesapeake – and we have drilled a few wells outside that window, but for the most part, it’s within that window with the carry.

Ron Gajdica

Also, if you look at EVEP’s acreage position, of the approximately 150,000 net acres that EVEP has, most of that is in the EnerVest operated category and very little of it is in a JV with Chesapeake. And so our – from a EVEP perspective the exposure to Chesapeake is minimal.

Mike Mercer

Yes. Let me be specific, which I think we have. Roughly 20,000 acres is Chesapeake operated or outside operated and the other 130,000 or so approximately acres is operated by EnerVest. And so the bulk of EVEP’s exposure is to EnerVest and EnerVest has no debt.

Ethan Bellamy – Robert W Baird

Thank you, gentlemen.

Operator

Thank you. And that does conclude the question-and answer-session. I would now like to turn the call back over to management for closing remarks.

John Walker

Well, thank you, Camille. And thank you, everyone for putting up with my babble on things. And we think that we had a very good first quarter and we appreciate your interest.

Operator

Ladies and gentlemen, this concludes the EV Energy Partners First Quarter Earnings Conference Call. You may now disconnect. Thank you for using AT&T conferencing.

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