Executives
John Walker - Chairman & Chief Executive Officer
Mike Mercer - Chief Financial Officer
Mark Houser - President and Chief Operating Officer
Analysts
Jack Ripsteen - PCAP
Noah Lerner - Hartz Capital
Yves Siegel - Credit Suisse
Leo Gillman - ESI Group Incorporated
William Adams - FAMCO
EV Energy Partners L.P. (EVEP) Q2 2009 Earnings Call August 11, 2009 9:00 AM ET
Operator
Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the EV Energy Partners, L.P. second quarter 2009 earnings release conference call. During today’s presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions. (Operator Instructions)
I would now like to turn the conference over to John Walker, Chairman and CEO. Please go ahead, sir.
John Walker
Thank you, Brandi. I’m pleased to report on the second quarter. I’m in Seoul, South Korea, on a business trip and our other Executives are in Houston. So if there’s any communication issue, they will takeover for me. Relative to production, I think we’re right on guidance. The diversification of our fields in eight major Basins proved to be fortuitous.
We lost about half of our production in San Juan for about two weeks due to the processing plant being down, yet still we hit guidance. I think, also very important is our Austin Chalk continues to outperform. Our two new going wells have EURs, really the recovery there of over 5 billion cubic feet equivalent.
We’ve added an additional rig there taking us to two rigs operating. The acquisition that we closed July 1 is on budget and a well will be drilled there sometime before year end. Basically, with the July acquisition, which was our second largest competitor in the Chalk, as well as one that we’re closing on September 1, it will increase our total well boar exposure to about 1700 wells and that just increases our playground or opportunity to reenter those wells.
Our costs are down about 25% there and are continuing to fall. Relative to lease operating expenses, we’re viciously cutting our costs and have been really since last year. Our LOE is about 1 million below guidelines. I think it will continue to comedown even more. On EBITDA, it’s about 2 million above guidance and clearly this is part of hitting our production targets, cutting our capital, lowering costs, and the benefit of our $20 million in hedge receipts for the quarter.
With the $80 million in net proceeds from our offering and $35 million in excess cash flow, we lowered our debt from $467 million at the first of the year to currently $352 million. We’re proud of that. We told you, we’d do it and we got that accomplished. Our debt to cap ratio will not be allowed to rise to previous levels.
The acquisition and divestiture market is very active. EVEP will find some deals on its own, but will more than likely participate with EnerVest fund 11 in several of the large transactions that EnerVest is currently evaluating. We will not do them unless they’re accretive and I think you know that.
The three deals that EnerVest has done with EVEP participating in the two Chalk deals have been done at $6,000 to $6,500 per producing Mcf and at very favorable PVs. This is a market in which buyers are only paying for proved producing, since upside in most instances is uneconomic at these product prices as well as well costs.
I remain very proud of two things in our assets. We’ve not had a single impairment, so we’ve had no impairments and every field in our portfolio is generating positive cash flow in the second quarter and that’s ignoring hedges.
Our acquisitions and drilling cost are $1 to $1.40 per Mcf, and therefore we used $1.50 per Mcf in maintenance cost for the quarter, which is approximately 27% of the EBITDA or higher than our peers. We’re comfortable about continuing to inch up our distribution based upon strong hedges, the positive operating results that we’re getting, the buyer’s market and acquisitions and market conditions that we see over the next few years.
So I’m going to turn it over to Mike Mercer to go over the specifics of our second quarter report.
Mike Mercer
Thank you, John. For the quarter, we reported adjusted EBITDA of $33.1 million, that’s an 8% year-over-year increase and a 6% sequential increase versus the first quarter of 2009. Distributable cash flow for the quarter, which we detail near the end of our press release, was $18 million for the quarter, slightly down year-over-year, 2% down, but 7% sequential increase versus the first quarter of 2009.
Now, for the quarter, because of the equity that we sold in mid-June, we had a full quarter of distributions this quarter including the units that we sold, but we also had to accord interest expense for two and a half months of this quarter, because that the units weren’t sold and we didn’t collect the proceeds from the offering until June. So effectively, there was a little bit of not a double count, but the double hit there because, we paid the full distribution on all of the units, including the $4 million we sold.
The interest expense was higher than it would have been otherwise had we sold those units and used them to pay down debt at the beginning of the quarter. Interest expense was about $800,000 higher than we would have had if those units have been outstanding for the full quarter and the debt been reduced then.
Net loss was $31.6 million, which was $1.93 per unit. However, that included $44.5 million of non-cash net unrealized losses on our commodity and interest rate derivatives. That was primarily driven by the increase in oil prices from March 31 to June 30, partially offset by decrease in natural gas prices from March 31 to June 30. Excluding that mark-to-market loss, income would have been approximately $0.65 per common unit.
Production for the quarter was 4 Bcf of gas, 127,000 barrels of crude and 186,000 barrels of NGLs for 5.9 Bcfe, that’s a 23% year-over-year increase and just slightly down from the first quarter, a little under 2% decline versus the first quarter, but as John mentioned, we had a little bit of down time in San Juan due to a third party processing plant being down.
Our LOE, as John had mentioned, declined sequentially versus the first quarter of this year. In the first quarter of the year, it was a little over $11 million. It was $9.5 million in this quarter and our G&A, excluding the non-cash equity-based costs that kind of cash G&A had a slight decline quarter-over-quarter.
Also, if you’ll note, we recently added some new commodity price hedges running from 2010 up through a little past the first half of 2014. We continue to layer in hedges in the out years and added a little bit on in 2010 and ‘11 and ‘12. You can see that these were done at prices ranging from 641 in the early years to a little over $7 in the out years for natural gas and just under $79 for crude in 2010’ rising to almost $85 per barrel for 2014.
As we’ve mentioned before, we don’t view hedging as a one time activity. You’ll see us continue to layer in hedges in out years, especially in 2014, and in 2014 going as we move forward through this year and coming years.
With that, I’d like to turn it over to Mark Houser, who is going to discuss some of our operating activities for the quarter.
Mark Houser
Thank you, Mike. Just to reiterate a bit about what John started out with. We’ve once again increased our distribution our debt’s been reduced about 25%. We had a successful equity offering. We’ve made some attractive acquisitions, and we couple that with what’s been some strong operational performance, including both good production performance and cost reduction.
On the production side, we are around our guidance levels. Our diversity of assets again is, key. Our Austin Chalk is very strong. As a reminder, until these acquisitions, EVEP has owned a little bit over 13% of the Austin Chalk production that EnerVest operates. The net production to EVEP for last quarter was about 15.2 million a day. Again, that’s about 49% gas. Those new going wells are in particular very strong. Both wells are oily and have EURs in excess of 5 Bcf per well.
Oil volumes are higher in the Austin Chalk area, due to the higher than expected or due to the horizontal wells. We have some other new wells; the [Morris Quinn] well and the Georgetown produced over $5.5 million a day for its first 40 days. That’s a very strong rate for the Chalk. Again, keep in mind these wells due to fine relatively quickly, but the IP is typically an indicator of alternate recovery, which is encouraging.
We also have a well, the reason to set that's in both B and the D zone that’s flowing over 350 barrels a day and 660 Mcf a day. So again, continuing to have good results in there. Another big Basin for us is the San Juan. The Ignacio shutdown is now behind us, for the quarter about 7% below, where we hope to be due about a two week shutdown at plant. However, as we look at it production has been restored and overall volumes year-to-date are still near where we expected they would be, which I think speaks to the good performance from the field and early on the wells now at the plants back in place, they are coming right back in line.
In the Monroe area, if you recall in past quarters and last year certainly, there were some curtailment issues relative to product market access. We’ve been able to avoid that curtailment this year, and maintain production above guidance levels. I do want to mention that our other assets are performing reasonably well, but really across most basins, especially in Appalachia, we are getting some increased line pressures, as storage continues to fill and that’s having some impact on our production levels.
We’ve reflected that generally in our guidance so far and will, but again, that’s just something our operating people are fighting everyday. On the operating expense side, there’s been a huge effort to improve both absolute and per unit costs. This effort involves reducing costs in many areas, field labor, compression, vehicles, utilities etcetera. The list goes on and on, and our operating team has been very successful in making this happen.
Second quarter LOE costs of $1.61 per Mcfe are the lowest unit costs in EVEP history and are 13% below first quarter and 36% below last year’s costs. Absolute costs are down over 20% from year end run rates and our efforts to continue to keep costs moving downwards are going to continue.
We look to the capital side; EV has spent about $9 million year-to-date versus our budget of about $17 million. We are now targeting about $16.4 million a year, primarily in the Chalk area, but we are going to be drilling in a couple of other areas very, very on a pretty low level towards the end of the year and doing some workovers.
Our maintenance CapEx provision at about $1.50 per Mcf, would imply that we’d be spending about $36 million for the year. I want to point out that our spending including
our capital and these two acquisitions we’ve done in total would be $32 million. So, an essence, these acquisitions are provided for in our coverage ratio.
In terms of drilling and capital activity, we’ve recently increased to two rigs running in the Chalk, again, as a reminder, we have about a little over 13% interest in existing assets and our new assets we’re acquiring will have a 15.5% interest in those properties. We’ve had good recent results with the boring; the ramp up with two rigs will run through the remainder of the year on the existing acreage and on the new acquisition acreage.
Our costs have been reduced as John mentioned about 25% on drilling. I also want to point out a Apache is still somewhat active pursuing the eagle footed Georgetown target through our format to them and as I understand it, they’re planning to drill another well in the gas window for the eagle fertilizer this year.
Just a brief summary on the acquisitions, we’ve done two attractive ones we feel in the heart of our Chalk position. In total it’s going to cost us about $17.5 million net and we’ll be acquiring approved reserves of a little over 12 Bcf and $6.1 million a day. This really increases the dominance we have in the Chalk. They’re at attractive benchmarks of around 6100 per Mcf per day and about 1.43 per Mcfe.
Again, we don’t really buy on benchmarks, we buy on discounted net present value, but we are buying at attractive discount rates as well and again, this gives us about 343 wells to reenter with new extended laterals on some of those at a low cost and the last thing on that is the takeover of operations will require minimal staff additions. We know these fields, we have people in these fields and we’re taking them over frankly, very effortlessly.
So, with that, I will turn it back to John.
John Walker
Brandi, I think that we’re ready for questions.
Question-and-Answer Session
Operator
(Operator Instructions) Your next question comes from Jack Ripsteen - PCAP.
Jack Ripsteen - PCAP
One, you said guidance, but I didn’t see any in the press release, so if there is some update, and less up exchange lets fine, and the other is with respect to CapEx, I think I heard you say $16 million in actual cash CapEx excluding acquisitions, but a more normalized level being 35, with acquisitions could be technically a part of that CapEx. I’m I hearing that right and is that proper interpretation? Thank you.
John Walker
Basically what we’re targeting right now based on our current budgets for the year, it looks like we would be spending around 16.4 on development activity, okay? The maintenance capital provision we have in our forecast of distributable cash flow would say that we’re going to be around $36 million.
Mike Mercer
Our estimated maintenance capital, it’s not an amount that we necessarily spend, it’s an amount that we put aside or deduct from distributable cash flow, which is our estimate of the amount that would need to be spent based on our production levels to maintain reserves and production over the long term.
Jack Ripsteen - PCAP
It sounds like you’re actually coming ahead of those at this point if I’m hearing you correctly?
Mike Mercer
That’s right as a matter of fact, even in cline and that was the point I made which may have been a little confusing, Jack, is even if you add in the acquisitions that we’re doing which are going to increase production, we’re still spending less than we’ve set aside just to maintain production.
Jack Ripsteen - PCAP
I guess another way to ask the question, maybe get a little more details it cheaper now or are there opportunities that are cheaper now to spend on acquisitions than there are to say put money into the ground so to speak, in existing wells?
Mark Houser
Let me answer that. We’ve EnerVest itself operates 13,000 wells in 12 states, so we’re seeing operations in a lot of places. We do not drill a well unless it chiefs a risk adjusted 20% return and there is only one area in the whole company in the EnerVest in which we are achieving that return and that’s in the Chalk. So we’ve gone from 20 rigs operating this time last year to two. We totally ignore hedges in terms of making drilling decisions.
Jack Ripsteen - PCAP
So it has to be economic on the ground versus with the hedging component?
Mike Mercer
That’s correct.
Jack Ripsteen - PCAP
Okay.
Mike Mercer
Jack, your other question regarding guidance, we published guidance I believe, it was in March with our announcement of our 2008 earnings. We don’t publish by quarter. We published it for the year 2009.
Jack Ripsteen - PCAP
That’s what I assumed. I just wanted to make sure there wasn’t something I was missing in the release.
Operator
Your next question comes from Noah Lerner - Hartz Capital.
Noah Lerner - Hartz Capital
Real quick, Mike, roughly could you give an estimate of the percentage you’re hedge for each of the second half of ‘09 through ‘13 at this point?
Mike Mercer
Based on current production levels, we are hedged for the remainder of 2009 second half of 2009 between 85% and 90%. For future periods, that does decline, Noah. Because as you know, we’ve limitations on the amounts that we can hedged under our credit agreement, it’s basically 90% of our proved develop producing production in our most recent reserve report.
So that declined some. I don’t have exact percentages going forward, but it drops, I believe, to about three quarters next year and then probably about 5% a year after that. That’s based object current production levels, assuming we kept production flat. That’s through ‘13 or that’s through 2012 and 2013 a much lower.
In 2013, we currently have about 10 million cubic feet of natural gas per day hedged and we have 1,000 barrels of oil. So that’s the equivalent of 16 million cubic feet equivalents, so we’re only about 25% hedged there in 2013 as of now.
Noah Lerner - Hartz Capital
I guess the other question I have, it’s really a combination of two things. I remember the presentation, I think it was back in January, February, John, you passed a comment that you thought natural gas we could see possibly as low as a $1.
I’m just wondering, if you could update us on what your current view of how low, we could go in the price of the commodity? What kind of impact you’re thinking that the high level of storage we’re seeing right now might have on dragging out the pricing coming back?
John Walker
I continue to believe that sometime after Labor Day, that we will see gas prices at $2 or below. Our storage as all of you are aware is about 3.1 trillion cubic feet. I think there’s a question about the practical amount that can be stored and I don’t know what that number is.
It’s probably somewhere in the 3.7 range, could be as much as 3.8. I’ve seen people say 4 trillion cubic feet and I really don’t believe it from a practical standpoint. We’re also experiencing in some areas for example, the consuming east takes a long time to get gas into those old oil fields, depleted oil fields.
They’re so far ahead of schedule that that’s one of the reasons that line pressures are going up and they’re already giving notice of curtailments. So we’re going to see this, not just in the Rocky Mountains, not just in Mid-Continent, we’re going to see it all over the country in my opinion where there’s going to be a lot of gas and gas competition, because we just have too much gas. It’s better for the industry, if that price drops sooner rather than later. If it waits until sometime in September, it’s going to be far more severe than if it started dropping sooner.
Operator
Your next question comes from T.J. Schultz - RBC Capital Markets.
T.J. Schultz - RBC Capital Markets
Just on your borrowing base, can you remind me on the timing for redetermination this fall, any discussions you may have had with the banks and your comfort level heading into that?
Mike Mercer
April 1 and October 1 of each year, semi-annual borrowing base redetermination, we’re still in the process of working out our mid-year reserves, have not begun the process with the banks yet.
John Walker
I think that, one of the things you asked about comfort. I think the thing that’s going to be important is the sort of the terminal price that banks were using. We don’t know what that’s going to be, but obviously with a probably, we don’t know exactly what our borrowing base is going to be, but with our recent acquisitions, it’s probably going to be at least 470 million. We feel very comfortable where we are right now with the 350 or so that we’ve borrowed.
Mike Mercer
T. J. you have to remember that, not only ourselves, but other MLPs, too upstream MLPs, we have long lived assets and most are pretty well hedged over the next three or four plus years. So, the changes in the borrowing base are really driven, not so much off of near term changes in bank prices or changes in bank prices over near years, but rather the terminal or out year pricing.
John Walker
So it’s really not an issue for us right now.
T.J. Schultz - RBC Capital Markets
I guess just second question. Just kind of a general thought on the acquisition market out there. Obviously, you’ve had success in the acquisitions in the Chalk. Just kind of general thoughts on, what you may be looking at and areas you may be looking at and what you see the market like as far as better as between buyers and sellers?
John Walker
There’s an acceleration in deals in the market. I think in reality for the shale players, basically there will be a lot of conventional assets that are for sale right now and will continue to be for sale. That would suggest that a good part of the Appalachian Basin is for sale.
I would assume that the problem in East Texas right now is the, Cotton Valley PUDs are uneconomic, but I would think except for the Haynesville, I would think a lot of the conventional assets will be for sale at some point in time. So, we’re going to see, Permian packages, I think it’s going to be a very active A&D market.
It’s very much a buyer’s market. We can tell you having done three deals, where basically we’re paying, good PVs for PDP only. The purchase and sale agreements don’t even resemble the purchase and sale agreements for 2007 and the first half of 2008.
Operator
Your next question comes from Yves Siegel - Credit Suisse.
Yves Siegel - Credit Suisse
I just wanted to follow up on Noah’s question and put it into the context of acquisitions and growing the company. The question really is, John, what’s your longer term outlook for natural gas given the shale plays and LNG? How does that enter into your mind between, acquiring natural gas versus trying to be more oily?
John Walker
Well, we’ve always been driven Yves, more by opportunity than by whether it’s oil or gas. I think that will continue. Of course, the Chalk, taking into account liquids and oil, it’s about 50:50 and ideally, we would like to be 50:50 and I do think that we are seeing and we will see some quality properties in the Permian Basin, but your question really at first was what’s the longer term outlook for natural gas and I don’t know the answer to that in actuality.
I think demand plays a big role and in particular power demand in how much gas is going to be used relatives coal primarily. Clearly we’ve been very successful in finding Shale’s and so, I have some concerns over the equilibrium price for gas over the next few years and LNG is just a walkover that I don’t think at least I’m unaware of anyone that precisely knows how to forecast that.
I know when I was working and others were working on the National Petroleum Council gas study in 2003, our Salvation was 20% of our gas coming from LNG imports and, of course, now we’re praying that not that much comes in. So, but who knows there’s sure a lot of export capacity that’s being added between now and 2012.
Mike Mercer
So, I think just one comment on that is what we’re seeing is, again, in terms of the way we acquire properties is on a discounted net present value basis and John mentioned we’re buying at attractive discount rates and we’re buying that based on the strip and we hedge a large amount of our production out several years, so we’re able to kind of lock in those distributions.
Then on the operating side, as much as we fight, I think prices and costs always go to that equilibrium they need to be at to make money and so our job is to just continue to be as low a cost of producer as we can and to be a lower cost producer than we bought based on, than we bought our acquisitions on as long as we can do that, I think that gives us great growth and frankly over the longer term.
Once these Shale’s are developed and get past those decline curves and people move on to develop other Shale’s, MLPs are a great vehicle for those kinds of assets as well. So, again, I think the next year, two, three years maybe really a great opportunity for doing acquisitions with the way we go about doing it and then we’re actually very excited about the window we see here over the next little while.
Mark Houser
I’ve been doing acquisitions for a long, long time and I think this maybe the best market that I’ve ever been in and anticipate that this market will be very favorable for at least the next year and anytime we can, pay for only PDP at very good discount rates and lock in our near term returns, then I feel very comfortable about that.
EnerVest itself is, of course, a major producer in the basins in which we operate, so we’re one of the biggest producers in Michigan, we’re, I think, the sixth or seventh largest producer in Appalachia, we’re by far the dominant producer in the Chalk, we’re one of the bigger producers in our part of the San Juan Basin and those big positions help us in terms of driving down our costs.
Mike Mercer
I was just going to say that, from a longer term perspective, if you sort of dollar average your acquisitions, you probably are going to do pretty well over the long term.
John Walker
Yes. I agree and you have to remember that our in excess of a million acres in Appalachia was acquired for about $10 an acre.
Mike Mercer
Ours being EnerVest as a reminder on that as well, EV has about 15,000 net acres itself in West Virginia, in Northern West Virginia and we are actually talking to some people right now, encouragingly about some potential joint ventures on those acres.
Yves Siegel - Credit Suisse
You are just talking about Marcellus or Mars?
Mark Houser
Marcellus. Yes.
Operator
Your next question comes from Leo Gillman - ESI Group Incorporated.
Leo Gillman - ESI Group Incorporated
I’m a new comer to this EV, as an investment opportunity and I’ve been quite impressed with everything that I’ve read so far and happy with my investment. I do have a question, though, regarding the sustainability of the losses on the derivative mark-to-markets. I know they don’t affect your cash flow and don’t really affect your liquidity as such, but over a long period of time, what are your forecasting with regards to realization of these mark-to-market losses and at what point will they start to hurt?
Mike Mercer
On the hedge accounting, the unrealized mark-to-market losses; actually, you could think of in a way is a good thing. That means that prices have gone up, they are higher than the price or they have moved closer to the price that which we’ve hedged. If those become realized losses, it’s because the actual price at which we sold our production was higher than it would have otherwise been.
In other words, any realized hedge loss is to the extent that those increase is offset by an increase in the price in which we actually sell the commodity when we produce it.
Leo Gillman - ESI Group Incorporated
I realize that, but isn’t there also a direction that can move where at some point it becomes unprofitable regardless?
Mike Mercer
Let’s say that, since we’re not ever 100% hedged, to the extent that commodity prices. Let’s say commodity prices start rising and continue to rise. We would continue to have unrealized mark-to-market losses and when those hedges settled, we would have either a smaller gain or a larger loss depending on the situation than we would have otherwise had commodity prices not increased. If we’re say, 70% hedged, we’ve locked-in prices on 70%, but the other 30% will realize the higher price.
So, on a 100% of our production, we’d be receiving the higher price. On 70%, we would have some in the situation you’re talking about, some hedged losses, but overall our cash flow would be higher.
Mark Houser
So, basically we receive at least the price we’re hedged at and if prices go up, we receive even more.
John Walker
Let me add that the one timeframe in which we’re sort of indifferent is because we are 85% to 90% hedged for the remainder of this year. If the price of gas goes lower, which I anticipate, it will probably actually help us because the A&D market will become even more attractive as distressed companies are forced to sell assets at prior sale prices. So, I just think that the bankruptcy process becomes something that in which we’ve bought assets attractively and we will continue to do that.
Operator
Your next question comes from William Adams - FAMCO.
William Adams - FAMCO
Just wanted to ask you what percent of your production in the quarter was from the
Austin Chalk?
John Walker
Well, we had a figure I mentioned roughly 15 million a day, which I believe that’s about 20% of production from the Chalk.
Mike Mercer
22%.
William Adams - FAMCO
I guess my question is my perception of the Chalk was that it’s a very profitable area for you, but maybe the decline rates might be higher than other areas. Could just maybe comment on that?
Mike Mercer
I think the initial decline rate on new wells is steep. I mean some of these wells come down at 30% or 40% initially, sometimes even more. The base decline rate of the Chalk as probably in the kind of 10% range or something like that, PDP. Part of the reason that we like the Chalk so much is that, so much of our production, whether it be the Monroe asset, the San Juan asset, it is just as flat as it can be. It’s got like a 3% terminal decline or 4% and the Chalk is a good blend on that in terms of providing some growth and some newer term cash flow for the portfolio.
So we wouldn’t want to have an MLP that’s all Chalk, but as we grow the company to have components of it that are, again it gives us more up side, it gives us a good blend on the portfolio side and it also gives us some oil and some liquids. So that’s kind of been the thought process.
As I mentioned, Bill, in buying these properties in particular, because of our concentration in the Chalk, we literally added, I think on a $17 million worth of acquisitions net to EV, but more importantly about a $110 million in gross acquisitions that EnerVest, bought in the Chalk. I think we added about five or six people. So it’s just really synergistic with what we have.
John Walker
Something that people don’t realize is that the average Chalk well has a life of 44 years. As it breaks over from a hyperbolic to an exponential decline, that decline is 8%. Now, it’s not 3% or 4%, it’s 8%, but it’s not, I think, as steep as the perception might be.
Operator
At this time, we have no further questions. I’d like to turn the call back over to management for any closing remarks.
John Walker
I don’t really have any additional comments as I think that we’ve reiterated this was another good quarter and I think that we can comfortably say that so far into the third quarter our production continues to be on target. So we feel very comfortable about the situation that EV is in.
I want to emphasize one more time that, distributions are extremely important to us. Management didn’t spend $40 million buying units in the open market last year without feeling like the distribution would continue to be a real priority and something that we could at least we can focus on trying to maintain. I’d like to thank everyone that called in and listened on the call.
Operator
Ladies and gentlemen, this concludes the EV Energy Partners, L.P. second quarter 2009 earnings release conference call. You may now disconnect. Thank you for using ACT Conferencing.
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