EV Energy Partners, LP Q1 2010 Earnings Call Transcript

| About: EV Energy (EVEP)

EV Energy Partners, LP (NYSEMKT:EVP)

Q1 2010 Earnings Call

May 11, 2010 10:00 am ET


John B. Walker – Chairman of the Board & Chief Executive Officer of EV Management

Mark A. Houser – President, Chief Operating Officer & Director of EV Management

Michael E. Mercer – Chief Financial Officer & Senior Vice President

Frederick Dwyer – Controller of EV Management

Kenneth Mariani – General Manager Eastern Division

Kathryn S. MacAskie – Senior Vice President Acquisitions and Divestitures


TJ Schultz – RBC Capital Markets

Richard Dearnley – Longport Partners


Welcome to the EV Energy Partners, LP first quarter 2010 earnings release conference call. 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) Now, I’d like to turn the conference over to Mr. John Walker, Chairman and CEO.

John B. Walker

In attendance here in Houston we have Mark Houser, Mike Mercer, Fred Dwyer, we’ve got Ken Mariani in from our Charlestown West Virginia Office where he runs our eastern division and for our last phone call we’ve got Kathy MacAskie here who is Senior VP. This is her last week, she’s done a terrific job for us and we wish her well in her future endeavors. I’m going to provide an overview and then Mike and Mark will provide more details on our financials and offer [inaudible] for the first quarter.

The big event of the quarter was the closing of Range’s Ohio properties and EVEP’s share was roughly $150 million. Although about 7% of that didn’t close because of a lack of consents and other issues. We hope that our support of Range’s work and its irresponsibility in this area that we will have these issues resolved so that we can get it closed on the full amount by either the third or fourth quarter. On February 12th we issued 3.45 million common units and received $94.7 million to finance about 64% of the final acquisition. I want to point out that 31% of the reserves are oil and 35% of the cash flow is oil from this acquisition.

In the first quarter we received no production from the Range’s properties but have suffered the full dilatation of the incremental 3.45 million units and I think all of you understand that. In addition, the oil in the tanks at closing is treated strangely, at least by my terms by accounting by creating a non-recurring $240,000 hit to LOE in the first quarter and an anticipated $3 million onetime LOE increase in the second quarter and Mike will explain that.

Taking in to account Range and EXCO combined, we added 810,000 acres and approximately 7,000 wells. The most important feature of the acquisition is that we project that production in 2014 from the Knox formation will exceed that of the PDP Clinton sands. Relative to the quarter, all measurements where within guidelines. Mark will discuss in detail some of the production short falls because of freeze off, free gas in Appalachia, capital spending reductions versus our budget and our first dry hole in the Chalk. All of these caused about a 3% short fall in production from the midpoint of guideline.

Gas prices declined throughout the quarter and as I’ve always emphasized we do not spend capital if we cannot receive a risk adjusted 20% rate of return on it. For the quarter and full year we have reduced our capital budgets which Mark will discuss. To me that translates in to more money for Range type acquisitions.

As a separate matter, you will notice a subsequent event announcement of our sale of undeveloped acres for $5 million. Because of EVEP’s large HPV acreage position in a lot of developing plays, you should expect to see further joint ventures, farm outs and outright sales in ensuing months and I can assure you of that. For example, there are recent announcements in Ohio and Michigan about the Utica Shale. Our 1.6 million growth acre position in Ohio means that any new play there has to come through us.

The outlook for natural gas prices this year probably will get worse but my concern is a likely oversupply situation for many years implying I think a gas price cap of something about the order of $6.50 tops. That’s not all a bad thing though, it’s allowing us to acquire assets for only PDP and specific basins. Let me explain by talking about our A&D strategy and asset positioning that began much more than a year ago. Both EVEP and EnerVest, its parent are building areas of concentration and in some instances areas of dominance.

With the EXCO and Range transaction, EnerVest partnerships and EVEP produced a gross amount of 87 million cubic feet equivalent per day in Ohio which is 25% to 30% of the state’s production. We operate there about 7,800 wells and control 1.6 million acres. You cannot be efficient with scattered acres and wells. With our concentration we’re driving down costs of course and we have large pools of gas that we can market and I think that is going to be very important in the gas market over the next 10 years or more but we can also justify buying from transportation which people with scattered production can’t justify.

As important in EVEP’s big three basins: the Appalachia; the Austin Chalk; and the San Juan, there are plays developing that will come through us as I have already mentioned. In the Chalk EnerVest and EVEP have one million acres. Not only is the Eagle Ford below the Chalk but the Chalk itself has rarely been fraced at all and the gas in place is enormous. Something you probably don’t know, the matrix for the Austin Chalk is greater than for the Eagle Ford. We will soon do the industry’s first multistage frac in the Chalk.

In the San Juan there are numerous conventional and unconventional reservoirs that are under exploited. Our upcoming horizontal well in Bear Canyon will, we believe, be the first multistage horizontal frac there. In all three basins we have major concentrated positions and are encouraged by our ongoing work for the past year. We will discuss these in more details at a planned analyst and portfolio managers’ meeting in Houston in late June.

Now, Mike Mercer will provide more details about our financial results and Mark Houser will discuss operations.

Mark A. Houser

For the first quarter of this year our adjusted EBITDA was $32.2 million which is 3% increase over last year’s first quarter and approximately a 7% decrease over the fourth quarter of 2009. Distributable cash flow was $20.1 million, about a 19% increase over last year’s first quarter and approximately a 5% decline over the fourth quarter of ’09. Our production for the quarter was 5.83 bcfe. That’s about a 3% decline over last year’s first quarter but is really flat versus last year’s first quarter if you adjust out those NGLs that you may remember we had produced earlier but ended up having those fraced, sold and booked under GAAP in the first quarter of last year. It’s also approximately a 6% decline in total production from the fourth quarter of ’09 or about a 3.4% decline in daily production.

Net income was $46.1 million or $1.68 per unit. Now, that included a $32.7 million non-cash mark-to-market gain on our commodity interest rate derivatives and that you know, was primarily due to declines in prices, specifically gas prices from January of this year through March of 2010. It also included a $1.1 million non-cash compensation expense. Excluding these amounts, net income would have been approximately $14.5 million for the quarter.

In LOE for the quarter, as John has mentioned, we had relatively small but we want to mention it here, a $240,000 non-cash inventory expense and that relates to the crude oil that was purchased in the EXCO acquisition. As some of you may know, under GAAP accounting when you purchase crude inventories, you have to book them at the current market price of the commodity and because of that it runs through the income statement, the LOE, at that higher price $80 a barrel rather than your production costs. It’s kind of a onetime thing. it’s a non-cash charge, it’s really just part of the purchase price being moved quickly through the income statement and as those inventories are produced and we typically do it in about a quarter that rolls off.

The reason we want to mention that and John had mentioned it briefly was that in the second quarter of this year we would expect approximately a $3 million charge to LOE. This is a non-cash charge and it simply relates to the fact that when we close the Range acquisition we have to allocate value to the crude inventories that are in the tanks that we acquire and those are booked, as I said, somewhere between $80, maybe up to $90 a barrel and those run through LOE at that price. So instead of the typical price that we would have running through the LOE of maybe $11 or $12 a barrel.

That will be a onetime thing you should look for next quarter. We did not put that in our guidance, it is a non-cash charge and we will have those as well as other companies any time we make acquisitions that have significant crude inventories in the tanks at the time of acquisition. At the end of the quarter we had $326 million of net debt. That’s after funding the closing of the Range acquisition on March 30, 2010.

Now, turning to our adjusted guidance that we published here with the quarterly numbers, the reason that we wanted to publish adjusted guidance is number one, we did not close on the full amount of the range assets. As John had mentioned there were some that still have third party consents that are to be obtained. When we published guidance, it was significantly before closing and we assumed we were going to close on all of Range acquisition at the end of the quarter.

So, we needed to adjust for the fact that we didn’t acquire all of that production. Now, we also only spent $130 million on that acquisition instead of $152 million. It was about $10 million less than we had initially planned so we had lower capital required for that acquisition. We also, because of commodity prices, specifically natural gas prices and where they are today have decided for the moment to reduce our capital budget by about $7 million or about 25% of the total for 2010. Most of that reduction will incur in the second through the fourth quarter, although we did spend a little more than $1 million less in the first quarter of the year.

If you combine those two factors and look at our adjusted guidance, the key affect on the guidance versus what we had before was approximately a 3% reduction in our midpoint of our guidance on production and also a $7 million reduction in drilling capital expenditures. Now, as we’ve mentioned many times there are different ways that we can go about maintaining our production levels and the fact that we only have in the budget about $18 million for cap ex this year now and the fact that we have estimated maintenance capital is running about $32 million or so per year, as you can see we have quite a bit left over that we can use for acquisitions capital that could replace this production and increase it.

However, when we put out guidance we never assume any sort of acquisitions, even modest add on acquisitions that are effectively a replacement for drilling which is what we did if you remember back in 2009. We cut back on our drilling budget quite a bit but actually during the year maintained our production levels because we ended up doing some modest acquisitions throughout the year. So to the extent that commodity prices rebound and we either drill more or if we end up closing on all of the Range acquisition that we didn’t close on in the initial closing or make some small incremental add on acquisitions we would revisit our guidance at that time and if it were meaningful would probably come out and adjust it back upwards.

Now, I’d like to turn it over to Mark Houser for a review of our operations for the quarter.

Michael E. Mercer

to year with record snows and cold temperatures in Appalachia, high snow fall in the San Juan and even freeze offs in the Austin Chalk up near College Station where I don’t think people were I don’t think people were allowed big warm coats. It’s actually a real credit to our operating teams that we performed as well as we did through these times.

As Mike and John mentioned, we managed to stay basically within our range and our production despite pretty crazy weather and despite slightly reducing our capital expenditures and [inaudible]. On the operating expense side we were high to our guidance due to a few main factors: the weather; the oil in tanks issue; work overs Mike has already discussed; and some MIT tests or mechanical integrity tests that are now required by the state in New Mexico on some shut in wells.

Most of our areas performed at consistent levels so I’ll speak to just to four main areas for the rest of my talk, the Jalmat area in Southeast New Mexico, the San Juan, the Austin Chalk and our Appalachia properties. In Jalmat perhaps one of the biggest challenges for EVEP was the work over and development program for the Jalmat field. We originally planned to spend around $7 million on 12 drill wells and eight recompletes this year in the Seven Rivers and Queen formation.

After performing four recompletes this winter we weren’t pleased with the results and have therefore put them on hold until we can evaluate further. We only spent about $400,000 or something in that range relative to $6.7. These projects are now deferred as we would rather acquire properties with this money as the projects just don’t meet our hurdle rate. This will save us over $6 million but reduces our production by about 700 mcf a day for the year.

In San Juan, our properties encountered the most snow they have seen in a few years. There was pretty significant snow pack through the first quarter which limited some access. There was actually a fairly significant snow as late as two weeks ago in the field. Through the first quarter this hampered production somewhat due to more than normal freeze offs and some higher line pressures. Productions recovered nicely so far in the quarter. Some of our gases actually shut in for about a week due to a plant turnaround in April, however we are getting back flush production which has minimized any significant production impact for the second quarter. Putting it in to perspective, the quarterly average for the first quarter was about 8.5 million a day and last week we were producing about nine million day in the San Juan net.

From the development perspective things will pick up later this year. As John mentioned our Bear Canyon well is a horizontal pud scheduled to spud the first week of July targeted in the Gallop formation. We have a 35% interest in this well and we’re actually acquiring other interests in this well. We also had some other Mesaverde in fills we planned for later in the year.

If I move to the Chalk where EVEP has a 13.3% interest as you’ll recall in a major investment by the EnerVest partnerships. Our Austin Chalk assets have continued to perform very well and generate tremendous cash flow after capital for EVEP. We’ve continued to run a two rig program and have had good results. Unfortunately, the first well of the year the [Weedon-Weedon] was what we could consider our first dry hole out of the over 30 wells we’ve drilled so far in three years in the Chalk.

We drilled the [Weedon-Weedon] in a relatively new area. We were concerned that this area may be prone to excessive water production. We were somewhat encouraged as we drilled and eventually completed the well but the well came on producing only water like some initial Chalk wells do. Unfortunately, it never dried up in to gas or oil production and we subsequently moved off the well.

Fortunately, statistics do work for the good as well in the Chalk. Our next four wells have been successful with a combined rate of 8.2 million a day and 460 barrels a day across those wells. We are currently drilling two wells the Johnston No. 2 which will be our first multistage frac that John mentioned and the Schulte No. 2 which is our second well in the Chesapeake acquisition. We’ve also maintained an active work over program with six to eight service rigs active across our fields mostly focused on water frac and [inaudible] stimulations.

Due to the dry hole and bringing wells on a bit later than planned partially offset by good work over results, first quarter production was about 500 mcf per day below where we expected. Moving in to the second quarter the new wells and continued work overs put us back on pace. We did face about a week of production downtime in the second quarter due to a turnaround on the DCP Giddings and at the NGL plant in Sweeney. Fortunately, these occurred pretty much simultaneously and are back running. We’ve had strong flush production since then as well and so we anticipate minimal impact there for the quarter as well. Again, putting it in perspective, last quarter production was about 16.8 million a day and last week production was about 17.6. So that includes some flush but you get the message.

Finally, as I turn to Appalachia, the primary focus was the effective integration of our two most recent purchases, the $130 million purchase of EXCO’s Ohio assets and the $323 million off Range’s Ohio assets. EV Energy acquired a combined $170 million in these transactions and other EnerVest private partnerships acquired the remainder. Putting it in perspective the EnerVest family now manages over 8,700 wells in Ohio and is by far the largest producer in the state. The properties under management include 1.6 million gross and about 1.45 million net acres. EV Energy itself has over 288,000 gross acres in Ohio.

Led by our Charleston West Virginia team, we spent the quarter transforming three operating entities in to one with our primary technical office in Charleston and our production managed from Hartville Ohio. As in most of Appalachia, labor costs are a key driver of overall operating costs in these Ohio properties. Due to the synergies of these properties we were able to reduce the technical and operational staff managing these properties by 42% from 265 to 155 employees.

Now that our team is in place we are focused on all aspects of reducing costs and enhancing production from reducing house gas that is used by royalty owners to enhanced compression, to enhanced automation and improved chemical utilization, work overs, drilling, etc. Production from the two new assets is actually doing well. On EXCO we’ve been running above level to estimates in our acquisition economics. On Range which closed on April 30th we have our first hand held meters now tracking production. These estimates in the K were running right around our evaluated May production rate. This is all encouraging for initial acquisitions.

On the drilling side we began EnerVest Knox drilling in April. We anticipated drilling Knox wells on the EXCO and Range properties for EVEP beginning in the third quarter. We also have been gathering some new seismic data and reprocessing existing seismic data on these properties. Our GSI scientists in Charleston, Columbus and Houston are continuing to evaluate other potential plays across this acreage.

Finally, we’ve begun the evaluation of several oil fields including the [Canton] oil filed which we now operate and own a majority of. This is a relatively large field and has never been comprehensibly evaluated for water flood or any sort of enhanced recovery due to its previously fragmented ownership.

That’s kind of a summary of what we’re doing across the asset base and I’ll turn it back over to John.

John B. Walker

We’ll open it for questions.


Question-and-Answer Session

(Operator Instructions) Your first question comes from TJ Schultz – RBC Capital Markets.

TJ Schultz – RBC Capital Markets

I guess it sounds like you’re going to start drilling or you have started drilling a couple horizontal wells in the Chalk, or one in the Chalk. Can you give me a little idea on cost to drill that and kind of what you expect there?

John B. Walker

Well, every well that we drill in the Chalk if horizontal and every well that we have drilled has been horizontal. We’ve got two rigs operating right now. we will continue to have two or three rigs operating there all year. Plus, we have anywhere from six to nine work over units. What I was talking about is a multi stage frac in the Chalk. The Chalk is over pressured and it has fractures, vertical fractures so when we drill in to it we don’t even treat it, it just comes on naturally.

We’re going back in to some of the existing well bores and fracing them for the first time and we’ve had quite a bit of success in doing that. It’s a very high rate of return. But, we’re going in to an area that has been fairly tight and we’ve had some marginal wells in that area and we’re going to do a large multistage frac in it to try and attack not only the factures but the matrix for [inaudible] that I mentioned in my opening remarks. We think that the Chalk has a lot of potential essentially as an unconventional play and of course we overwhelming dominate the Chalk so that makes it also of interest.

Mark A. Houser

Your other question is about cost and the last five wells that we have drilled have averaged about $3.1 million drilling complete horizontal wells.

John B. Walker

These wells are we go down anywhere from 10,000 to 14,000 or 15,000 feet and then we’re drilling out probably on average about 4,000 feet on one lateral and some of the times we’re doing multi laterals.

TJ Schultz – RBC Capital Markets

Just jumping over, you talked a little bit about selling some unproved acreage here in the first quarter and talked about that potentially being an ongoing deal the rest of this year. I’m just trying to get a feel for kind of what scale are you talking about? Are we looking at more this type size deals or are you looking at anything more significant here or what’s your thoughts on selling acreage through the rest of the year?

John B. Walker

I think you will see more ad maybe larger. We’ve been in a joint venture and we sold some acreage outright in the Marcellus. We still retain 21,000 net acres in the Marcellus. Obviously, the Utica is getting some comments now. Our acreage position, our HVP acreage position absolutely dominates that play and so we’ve obviously heard from people on that. I guess we’re the fourth largest player in Michigan with some of the activity up there. It’s a Utica shale equivalent, the Point Pleasant is and so that, the Chalk and what we’re doing in unconventional and conventional in the San Juan you’re going to see a lot of activity out of us.

At the same time I want to remind you we’re an MLP we’re not an E&P company. We’re not going to expose $25 million to see if something works. Something more typical of what we would do since we in general have 12.5% net leases, we’ll deliver an 80% net lease and we will then be paid for acreage. We’ll keep a 7.5% override and we’ll be carried and then retain anywhere from 25% to 50% in a play. That allows someone else to take at least the initial risk and most of the risk and at the same time these can be fairly large dollars to EnerVest.

TJ Schultz – RBC Capital Markets

One last thing, can you touch on I guess you just had your borrowing base redetermination. It looks like it was maintained at $465. Can you talk about what price decks the banks are using? I guess I was expecting a little bit of an increase with the recent acquisitions.

Mark A. Houser

Well, we could have requested an increase and we chose not to. Remember, when you ask for a borrowing base increase you pay some significant upfront fees to increase the borrowing base and then you have ongoing fees for unused capacity. Since we don’t intend to borrow – right now we’re at $465 million borrowing base, we have about $325 million of net debt. We don’t intend to leverage ourselves up where we would need more borrowing base so our view was why pay these upfront fees for something we don’t plan on using.

One thing we did though is we went in and got a waiver from the banks which allows us to issue high yield debt without having any reduction in the borrowing base up to certain limits. You’ll see that we filed that amendment a week or two ago. But, we absolutely could have gotten a significant increase in the borrowing base had we wanted to increase it but we saw no reason to spend those dollars since we don’t plan on leveraging ourselves up to those kinds of levels.


Your next question comes from Richard Dearnley – Longport Partners.

Richard Dearnley – Longport Partners

I have two questions, on the last answer, is EnerVest, on farming in someone on these new multi stage fracs, is EnerVest going to be the primary farmee?

John B. Walker

At times I talk about puds and I need to clarify when it is EV Energy Partner or one of our other partnerships. The farmee in most of these transactions is both EVEP as well as some of our other partnerships so in general the areas where we have built concentrations is based upon both the institutional partnerships and EVEP. Now, our long term plan on the appropriate assets which they’re declining etc. would be to move those in to EVEP over time assuming approval from the independent directors from EVEP as well as the institutional advisory committees.

Richard Dearnley – Longport Partners

Then in terms of you said acquisitions in the gas area are now going only for PDP could you put a price tag on that in terms of price per proved developed? And then also how does that relate to the to say the PV 10 value both last year’s PV 10, the SEC value for ’09 and then the old way value for ’08?

John B. Walker

First, every acquisition is different, for example in the EXCO acquisition there was something in the order of $7,000 per day per flowing barrel flowing in but only 10% of it was oil. In the Range acquisition, as I mentioned 45% of the cash drain was oil and I think that was for $12,000 per flowing in but you have to take in to account the fact that it was a much higher component of oil in there. So, the reality is both were bought for something on the order of about a PV 12. We don’t even look – in acquisitions the proper way to do them is risk adjusted discounted cash flow where you’re engineering every well.

So all these rules of thumb frankly don’t work. Wall Street uses them because you don’t know what the risk adjusted cash flow that we’re using. But, I would say that if you want to use an amount in the ground, we’re buying these reserves from anywhere from $1 to $2 in the ground. There are a lot of acquisitions, I mean you’ve seen several recently where people are paying crazy prices. I won’t mention any situations but I mean that’s just not something you’re going to see us do. The great thing about delivering good returns over a long period of time is we know how to do acquisitions and we’re going to have a very disciplined approach to our acquisitions.

Richard Dearnley – Longport Partners

Does the PV 12 workout to five or six times EBITDA?

Mark A. Houser

I think that really depends on the transaction. Your differentials, your costs, it really varies but it generally seems like year in year out over time a lot of winning bids are won in the PV 10 to PV 15 range and some are bought for less and some are more but really whatever the price deck is, it seems like competition gets in at that level.

John B. Walker

I would say that we normally would see things paying out roughly in a five to seven year period. Your illustration specifically is going to be influenced by the decline rate in the area where we are buying. With a faster decline rate it’s probably going to have a different multiple, a lower multiple.


I am showing no further questions in the queue. I’ll turn it back to management for any further remarks.

John B. Walker

Thank you for taking the time to be with us this morning. Mike and I are going to be at the National Association of Public Partnerships in Greenwich actually beginning today and tomorrow and so hopefully some of you will be there and we look forward to visiting with you there. Thank you again and good morning.


Ladies and gentlemen that does conclude the EV Energy Partners LP first quarter 2010 earnings release conference call. Thank you for your participation in this event. You may now disconnect.

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