Good day, ladies and gentlemen, and thank you for standing by. Welcome to the EV Energy Partners, L.P. third quarter 2009 results conference call. (Operator Instructions)
I would now like to turn the conference over to John Walker, Chairman and CEO. Please go ahead.
Okay, thank you, Luke. Good morning, everyone. I have with me Mark Houser, Mike Mercer, Kathryn MacAskie and Fred Dwyer.
Our results in the third quarter were somewhat better than guidance. Our revenues were a little bit better. Our expenses were lower versus guidance but up versus second quarter because of our expense workovers, which were very successful, and Mark Houser will go into that. Our EBITDA was a little more than $1 million better than guidance, and Mike will explain the impact of doing our equity offering very late in the third quarter while having the full interest expenses for the quarter. We remain very conservative in setting aside maintenance capital, and we continue generating excess cash flow to continue to pay down debt or contribute to acquisitions.
Relative to the two Chalk deals that were closed in the third quarter, they're already producing ahead of our acquisition economics, and we've already drilled a successful well on the Chesapeake acreage. So we're off to a fast start, and it's bearing fruit.
The Appalachian acquisition from EXCO closes the 24th of this month. We're purchasing 350,000 acres and over 3,000 wells from EXCO. We paid only for the PDP. Of that 350,000 acres, 240,000 are Knox formation prospective, and we're experts in the Knox formation. In fact, in our acquisition economics - and we're confident about this - in 2013 after CapEx we expect Knox cash flow to exceed that of the PDP. So we're extremely opportunistic about this Appalachian acquisition.
We did an equity offering for 3.2 million units in late September and raised net proceeds of $72 million. Our debt us currently $282 million, but when we close EXCO it will rise to about $300 million. Our borrowing base was reconfirmed at $465 million, which we were pleased with. We have no impairments.
The only curtailment that we experienced during the third quarter was an NGL processing plant that's in the New Mexico Permian Basin area, and that was down a week or two and did have some negative impact, but we were able to overcome it with our diversity. And again, when you're producing in eight major areas, you can have something like that happen and that doesn't tend to create real problems for you.
We're positive cash flow in every one of our operating areas. Our hedges contributed $20.6 million to our results this quarter - that was our oil and gas hedges - and we added additional hedges particularly in the out years. We're the most hedged of all of the MLPs, and I think that as we look toward 2010 and the gas market, being the most hedged of all the MLPs just makes our investors feel more comfortable.
Relative to the A and D market, in 2009 it never developed as we expected. The banks never acted aggressively. The capital markets, both the bond and equity, provided a lot of money for folks that otherwise probably would have had to have sold properties and they never did. But we continue by having visits with the advisory firms that sell properties that we're going to see a very active calendar for the balance of this year and well into 2010. A couple of the majors have already announced that they're selling properties, and I believe that conventional assets for most of the shale players may be available.
And I guess it's time for me to offer my mea culpa in that I projected for about a year that the cash price of gas would be about $1, and the lowest it got was $2.50. But I continue to believe that if we'd gotten to $1 the outlook for 2010 would be a lot better.
But the reality right now is there's too much gas in storage, there's too much gas in the world - LNG - that's looking for a home, there's not enough demand, the shale players are spending a lot more than their cash flow - 35% to 50% more than their cash flow - the rig count is up 200 rigs since this summer overall, the gas supply is rising not falling, 2010's going to be a rough year for gas prices, and the good news is we're heavily hedged for 2010. We feel comfortable about 2010, and we will take advantage of 2010 as we have in 2009 to make some highly accretive acquisitions.
So, again, I think that there has been some optimism about 2010 gas prices. With the economy being what it is, with the gas supply being what it is, I think reality is starting to set in that 2010's going to be a rough year in the natural gas market.
I'd like to now turn it over to Mark Houser.
Thank you, John.
Briefly talking about production, as John mentioned, it's been a good quarter. Going first to the Chalk, we've continued to have strong production performance there. We've integrated the Chesapeake and Marathon assets very well. They're running about 3% over their budget. If you recall, in total EVEP has about a 16% to 17% interest in the Chalk activity of EnerVest in total.
We've already had two successful workovers on the Chesapeake and Marathon acreage that in combination have generated about another $1.9 million cubic feet a day. We have two drilling rigs running right now; we will actually have three for a short time as we're bringing in a new neighbor's high-end rig in going forward.
John mentioned we've drilled our first well in the Chesapeake acquisition. It's a well called the Westlands well which IP'd at about 3 million a day and 50 barrels a day, which is a nice down the fairway well for us.
Also in the Chalk we have a joint venture on our shallow Wilcox and [inaudible]-type tests, and over the next six months we'll actually be carried on six wells with a 35% carry to the tanks on that so, again, for no capital exposure for EVEP we'll be seeing good potential there.
Workovers have been performing well in the Chalk and also in other areas. Up in Michigan we've increased production by over 1 million cubic feet a day over the last two to three months doing some Antrim refracs. We've refracced nine wells for a total cost of about $450,000 and have gotten a great bump there on that. We also have some recompletes ongoing in our [Jalma] area and a few other places. And, again, a continued emphasis in the Chalk, so production wise things are going well.
John mentioned on the operating expense side we're continuing to see downward pressure on our fixed LOE costs. We have had a slight increase due to workover activity, but that's been very profitable for us.
The last thing I'd like to talk about is just a reminder on our new EXCO acquisition which we should close on the 24th. It's a $145 million acquisition. EVEP has about 17% of that acquisition. On an [8H] basis we're talking about 90.5 Bcf of reserves with our Knox potential identified. It's got about 2,800 wells, so a lot of diversity to it. The proved decline rate is about 8% early in its life, and it transitions over to a 5% terminal decline.
We've got a good bit of Knox upside. Right now we have scheduled five years of drilling at 25 wells per year. That will be part of about a 75well per year package that EnerVest in total will be doing, so that's going to give EV some real synergies and economies of scale as we drill that. These are very high rate of return wells. Our Knox historically over the past six years has generated about 50% rates of return under these prices, so we're real excited about that.
To EVEP's share, we'll be spending about $24.3 million and acquiring about 16 Bcf with our Knox potential. That will give us an incremental of about 2.5 million a day for EV, which is slightly above where we projected in the acquisition economics.
So generally it was a very good, steady quarter. We're excited with our new opportunity in EXCO and our continued opportunities in the Chalk and some of our other diverse areas.
And, with that, I'll turn it over to Mike.
Thank you, Mark.
For the quarter we generated EBITDA of $33.6 million. That's a 22% increase over last year's third quarter and 2% above the prior quarter of this year. And we generated distributable cash flow of $19.5 million, which is about 39% over the prior year's quarter and 8% over on a quarter-by-quarter basis, 8% over the second quarter of '09.
Now on our distributable cash flow, as John mentioned, because of the timing of the equity offering we recently did - we closed that, if you remember, on the last day of the quarter, September 30th, and used those proceeds to initially repay debt and for future acquisitions - however, because we didn't close until the end of the quarter, we had a full quarter effectively of interest on those funds since we didn't close until the end. So that will go away next quarter.
And we'll also have our Marathon acquisition, which only contributed one month, will contribute three full months in the next quarter. And, of course, the EXCO acquisition, which is closing this month, will contribute about five or six weeks into the fourth quarter.
If you look at it from a net income basis, we had a net loss for the quarter of $2.8 million; however, that included $16.6 million of non-cash unrealized losses on commodity and interest rate hedges and approximately $1 million for non-cash equity compensation expense, which is part of our G&A.
Also in G&A we had for this quarter a little over $100,000 of due diligence costs on the acquisitions that we've been working on. There was a change, as many of you may know, this year - new purchase accounting rules which require you to expense due diligence costs on acquisitions rather than capitalize them, so that was included in this quarter's G&A.
Back to the unrealized non-cash losses on hedges, that $16.6 million relates to hedges that run from October 1st of this year all the way out into 2014. Those hedges haven't settled, and that was strictly because gas prices at the end of this quarter, the future strip was higher than it was at the end of the prior quarter. So excluding those non-cash hedge losses net income would have been approximately $14 million.
Our production was 6.5 Bcfe. That's 30% over last year's production in the third quarter and a 4% quarter-over-quarter increase. LOE was $1.70 an Mcf. And other things of note - we had CapEx of about $2.5 million this quarter.
We've been able to throughout this year maintain our production levels with a minimal amount of CapEx along with some workover expense that we've incurred this year as we continue to try to maintain our production levels with minimal CapEx in this kind of price environment.
As John mentioned, our debt is down quite a bit. Our debt declined from the prior quarter by $60 million to $292 million at the end of the third quarter; however, during October we paid an additional $10 million of debt, so we're currently at $282 million. We would expect that to go up to somewhere around $300 million later this month after we close the EXCO acquisition.
We also note in the press release and you can read it - I won't go through it in detail - that we did add some hedges during this prior quarter. They were primarily oil-related hedges out into 2013 and 2014, all of which were done at above $80 a barrel. So we continue to move out into the future and lock in commodity prices to guarantee ourselves some level of minimum cash flow for distribution levels as we move forward.
That's it I think for our comments, and we'd like to open it up for questions - or John Walker has one more.
Well, I might make some additions to what Mark and Mike said.
In the Chalk we have seven to nine workover units operating, and so that is going to have some impact on expenses. But the rate of return on the results that we're getting is so good that you'll continue to see that, and that's been the major reason that we've been able to maintain production without drilling very many wells this year.
We continue to only drill a well and only operate drilling rig if it generates a risk-adjusted 20% rate of return, and for that reason we're not drilling a whole bunch of wells right now. We're drilling in the Chalk; we'll be drilling in the Knox. So those are the areas where we can at least meet if not exceed those rates of returns.
I'll turn it now over to Luke to see if there are any questions.
Thank you. (Operator Instructions) Your first question comes from Michael Blum - Wells Fargo.
Michael Blum - Wells Fargo
John, just on the topic you were just talking about, can you I guess just go a little further? I'm just trying to understand how you're able to spend less but yet maintain production. And then I guess the larger question related to that is do that make you re-think what you should be setting aside for maintenance?
Well, I know that there are some folks in the LNP business that are setting aside less and in some instances way less than 10% of their EBITDA as maintenance capital. We've always felt like that our maintenance capital is not what's happening today, but it's based upon our ability to maintain our production and reserves over the long term. And so that's the reason that we have continued to be probably roughly over time in the 24% to 33% of EBITDA range.
Now, clearly in a market where we can acquire things at a $1 to $1.40 in the ground, for us to be setting aside $2 doesn't make very much sense. But I think that something in the $1.40 or $1.50 range probably does make some sense right now, and we're spending less than that.
But I don't think that over time we can continue to go in and refrac wells and do this and maintain production forever and ever. I think we're eventually going to have to drill some wells. But again, we're very conscious about rates of return.
In the Chalk we have 1,700 well bores that we operate, and that creates a lot of opportunities to go in and do things to increase production. These wells up in Michigan where we've gone in and spent $50,000 per well but we've increased production from 25 Mcf to over 100 Mcf, those are great rates of return even with today's prices.
What would you say, Mark?
Yes, just one comment on that, too, Michael. EnerVest in total operates over 13,000 wells now, and that'll go to 16,000 here pretty soon. With that kind of economy, that kind of size, we start seeing things that we can repeat more.
And we're starting to learn more and more about being able to do that, as John mentioned, as an example the 1,700 well bores we have in the Chalk or the many wells we have in Monroe. If you find something that's working like, as an example, the refracs on the Antrim up in Michigan, you can typically repeat that a good bit because you have such a big set of opportunities. And so one thing we're seeing right now is, as we slowed our drilling activity down a bit, we've been able to focus on that, and we're just seeing some good opportunities. And that can help us for a good little while going forward.
And one of the things I said in my A and D comments was that I think, for example, the conventional assets in Appalachia are for sale, and we like these old, ugly wells that we can go in and pick up 300,000 acres, not pay for the upside, and still have some significant upside potential. And I think that we're going to see a lot of that over the next year.
Michael Blum - Wells Fargo
Just given your outlook in '10 for nat gas the way you outlined it, in terms of looking for acquisition opportunities does that make you more interested in gas assets versus oil or how are you thinking about that?
Well, we're always interested in both, but we're opportunists. And if it happens to be oil, that's fine. If it's gas, that's fine. What we're trying to do is buy things that are highly accretive for people who are willing to sell for the PDP and we can buy them for a good PV.
And right now I would say that based upon the Petrohawk and Parallel sales there's probably better opportunities for acquisitions in the gas market because people overpaid for the oil assets there. And we don't overpay. We're going to buy things on a fair basis, but we're not going to overpay for assets.
(Operator Instructions) Your next question comes from Kevin Smith - Raymond James.
Kevin Smith - Raymond James
You touched a little bit on your conventional Appalachian assets. Is there any worry that as some Marcellus wells come on and slowly mature and go to the lower pressure wells that some of the mature Appalachian wells will eventually be kind of forced out or how should I look at that?
The Marcellus wells will be in a completely different gathering system. They have to be. They're high-pressure wells. And so the key for us in terms of making sure that our production stays onstream is our own gathering system, but also where we need it from transportation.
And we're doing all those things. But we're a major player in the Appalachian Basin. We're one of the top 10 producers. And as a result of having such a big footprint in Ohio, Pennsylvania and West Virginia, we're still important in terms of gas flow, and we're able to arrange things with Columbia and Dominion, etc., that gets us in.
So I do think it's going to be more competitive every place where gas is produced, but the key for us is not necessarily trying to have a lower finding cost than Chesapeake or moving our gas better than Chesapeake. Our key is being able to move our gas better than any of the other conventional players so that our gas is always onstream.
And I do believe that we've thought a lot about that. We've been having a lot of meetings on it, and I think that we're going to be well positioned to do it.
Kevin Smith - Raymond James
Are there any updates on your format with Apache as far as Eagle Ford?
Apache is not drilling in the Eagle Ford currently. They have had some modest results in the Eagle Ford but really very good results in the Georgetown. And so in terms of us not putting up any money, we are receiving some revenues from that. And I think that as time goes by Apache, they've given us indications that they will be drilling in the gas leg of the Eagle Ford since their focus previously has been in the oil leg of Eagle Ford.
Kevin Smith - Raymond James
How many non-operated wells are you drilling the Austin Chalk or are you participating in, I guess?
Not very many right now. We're overwhelmingly the dominant player. Every now and then we'll participate in one. I don't think we're drilling a single one.
Yes, I don't know of any that we're drilling right now, Kevin.
Your next question comes from Leo Mariani - ARVC Capital.
Leo Mariani - ARVC Capital
Just curious. I'm sure you haven't set your budget down yet for 2010. Just curious as to how you are thinking about spending CapEx drilling versus acquisition dollars. It seems to me we've got a relatively low service cost environment. Commodity prices clearly have been kind of taken up here recently, hopefully setting up for a better year next year. Do you guys anticipate maybe putting some more money to work in the drill bit versus acquisitions?
Leo, we're actually right in the middle of our budget process, and a bunch of us will be traveling up to West Virginia next week and then meeting here at the end of the week on some of that. You're right; we are seeing some improvement in service costs, especially for conventional assets. The rigs and the capabilities we need are just not quite as strong as you need to drill 10,000 foot long horizontals.
So, as an example, on our EXCO deal right now, based on where costs have been historically over the last year or so, I think we have about 200 I'll call potential conventional wells to drill. With an improvement of about 30% in our cost structure you can be looking at 500 wells.
And so we're studying that right now, and I think the message is our guys are starting to see some more creative ways that we can increase our activity. To what level, of course, with an MLP, it's always going to be modest. I mean, that's the way we operate. But we do anticipate having some better opportunities as we go forward.
But again, our rule here is it has to be a 20% return based on where prices are.
And with the rig count having gone up 200 rigs since the summer, Leo, that has sort of stemmed the drop in drilling costs.
Now, the interesting thing will be if gas prices continue to be soft whether or not this rig count will continue to rise.
The thing that's a bit encouraging for us is a lot of that rig count is for horizontal shale drilling, and we're playing a bit of a different game.
Yes, I agree.
Leo Mariani - ARVC Capital
You mentioned Appalachia was potentially an area where maybe you could step it up a little bit with, obviously, the new acquisition you all did from EXCO. I'm just curious as to whether or not the Chalk kind of fits that same category.
Well, the Chalk, we continue to have really good returns out of our Chalk drilling program. I think as we mentioned earlier, we have two rigs running now. We're going to have three running for a very short period of time, and then we'll be back to two. I think as we digest these Chesapeake and Marathon assets more and as we continue to see some of the good results in various areas, we'll make some determinations on that as we go forward. But right now we think a two-rig pace is a good pace.
Thank you. There are no further questions in the queue at this time. Management, please go ahead with any closing statement.
Well, we appreciate everyone being on this phone call. Again, a good quarter; we're halfway into the fourth quarter, and I can tell you that our production results at this point in time continue to be good. There are no surprises. So I would anticipate that the fourth quarter would be pretty much as all of our quarters have been, pretty much in line with what we forecast.
By the end of this month we will have completed our whole budget process. And I think that we will be able to give you guidance into 2010, but we think 2010 will be another good year. I'm very optimistic about the acquisition market for 2010. So we think it's going to be a good year for EVEP.
Thank you very much.
Ladies and gentlemen, this concludes the EV Energy Partners, L.P. third quarter 2009 results conference call. You may now disconnect. Thank you for using AT&T Conferencing.
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