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Clayton Williams Energy, Inc. (NYSE:CWEI)

Q2 2008 Earnings Call

August 6, 2008  2:30 pm ET

Executives

Clayton W. Williams, Jr. – President and Chief Executive Officer

Mel G. Riggs – Chief Financial Officer

Analysts

Steve Orr – Orr Investments

Gregg Brody – J.P. Morgan

Brad Evans - Heartland

Sean Feeley – Babson Capital

Presentation- Financials

Operator

Welcome to the second quarter 2008 Clayton Williams Energy Inc. earnings conference call. (Operator Instructions) I would now like to turn the presentation over to your host for today’s conference, Clayton W. Williams, Jr., President and CEO.

Clayton W. Williams, Jr.

We’re happy to present some good findings today. As normal, we will ask Mel, our CFO to go into depth our financials for this quarter and after that then I’ll give an overview as to current operations and our future as we expect it.

So with no more ado Mel would you please take over.

Mel G. Riggs

First of all, I would like to address the hedge losses in the second quarter due to the mark-to-market on those hedges which had the greatest impact of anything on our second quarter results. After I go through that, we’re going to entertain questions if you’d like to ask a question specifically about the hedges, and then we’ll move into the remainder of the financial part before Clayton takes over.

As we all know, during the second quarter we experienced near record high product prices and at the end of June oil was trading right around $140 a barrel, and it had pretty much gone into a tango pattern into the future. Natural gas is trading above $13 per Mcf. And the benefit from these rising product prices, from our company’s standpoint, it was largely offset by a current quarter net loss on derivatives or hedges of $148.6 million compared to a $6 million gain in 2007, same quarter.

Of this hedge loss, actual settlements during the quarter were $35 million, most of which related to oil. Keep in mind we still have Southwest Royalty hedges where we’re capped at about $25 a barrel on quite a bit of oil. So we were way out of the money on those hedges. Those hedges are going to be gone at the end of September. We’re trading that contract currently. It will be gone pretty quick. So that will be behind us. So we had a $35 million actual cash loss for the quarter. The big hit though was the mark-to-market, which was non-cash. That total amount was an additional loss of $113.6 million.

This mark-to-market had no operating effect on the company at all. There were no margin calls or no requests for any collateral to secure these open hedge position. It was just sort of a calculation, a snapshot point in time, and it was a big number unfortunately. I mean, it was good to have the high product prices but again we didn’t really get the benefit in the income segment because it’s mark-to-market.

It’s important to note now that due to the recent pull back in product prices, our exposure to this mark-to-market has been dramatically reduced. And if product prices stay at current levels or continue to decline, the results going to be that we’re going to record a substantial income in the third quarter to reflect the change in the mark-to-market. And this is all done for GAAP reporting purposes, and it’s a big number. It affected the bottom line and profitability wise didn’t really have any impact on our operational results to any great degree.

Our Southwest Royalty hedges will again will roll off with the end of the September futures contract. Under that hedge position we’ve had oil pretty much capped at $25 a barrel and natural gas capped at around $5.15. So be glad to see that go away. We’ve had those hedges now for four years since we acquired the company.

Outside of the Southwest Royalty position, those hedges, for the remainder of 2008 we’ve got natural gas hedged at above $9 in Mcf. We’ve also got gas hedges on 3.6 Bcf for an extra hedge of $9.33 per Mcf. And then on the oil side we’ve got 1.4 million barrels of oil hedged at $85.35 for next year. So we’ve got quite a bit of substantial revenues hedged at fairly decent prices. Oil hedges are out, pretty far out of the money. Oil is heading in that direction right now, though, so we feel good to have – we feel fortunate to have the hedges.

And then we’re bringing on new production, you know, every day as we drill that’s not hedged. So we should be in a good position going forward and the hedging situation should be a lot clearer in the future, due to Southwest Royalty hedges kind of rolling off.

With that overview, I would right now take any particular questions about the hedge loss, the hedge position, whatever. Feel free to ask.

Question-and-Answer Session on Financials

Operator

(Operator Instructions) Your first question comes from Steve Orr – Orr Investments.

Steve Orr – Orr Investments

I wondered if you’d taken a look at the hedges over the years and done any analysis to see whether and I hope this doesn’t sound like a heresy but whether it’s really worth doing, whether the cumulative losses and/or gains, whether there are gains. I’m not sure about that. I’ve seen a lot of losses over the years. Just wondered if you’d taken a look at that to see whether it is worth it.

Mel G. Riggs

Well first of all I think we have to kind of split the hedges up. You know, we bought into a hedge position when we acquired Southwest Royalties and it was a pretty strained – by the time we bought Southwest Royalties though it was not that far out of the money. I think we were about $35 million out of the money on that deal in 2004.

Steve Orr – Orr Investments

Right. You inherited that. Yes.

Mel G. Riggs

We inherited it. And since then that’s contributed to over $100 – probably $120 million of our hedge losses of the last few years. So it’s been a – that’s been a big part of – it’s kind of been buried in the numbers. But that’s been a big part of it. In the past I think we had several years where we did well hedging. I think, obviously, we got into a market the last two or three years where the prices have just continued to go up. And I mean, I don’t know – you know, in hindsight yes, we wouldn’t have – we didn’t really want – we shouldn’t have hedged, but I think Clayton pointed out that we – somebody the other day said it well.

I think it was Warren Buffett said that “The rear view mirror’s a lot clearer than the windshield is.” And I think that’s true. It’s hard to see what’s going to happen in the future. And we know that we need a lot of – we need to secure our cash flow to have the money to drill, so we can put the money back in the ground. Clayton, would you like to add anything to that?

Clayton W. Williams, Jr.

I think that’s solid, that Warren Buffett said it well, said “In business, the rear view mirror is a lot more cloudy” I mean, “the windshield is a lot more cloudy than the rear view mirror.” That applies here. I don’t know that we’d have done a lot different. With the rear view mirror, yes, we’d be rich as Boone Pickens if we could see the future. But that’s all I have to say about that. Any other question on it?

Operator

As there are no further questions in queue at this time regarding the financial part of the presentation, I’d like to turn the call back over to Mel Riggs for the operations part of the presentation.

Presentation - Operations

Mel G. Riggs

So anyway, long story short here, primarily due to this mark-to-market loss on the hedge position, we reported a loss for the quarter of $21.2 million, $1.75 per share compared to last year’s net income of $8.8 million or $0.70 per share. The good news is cash flow from operations for the current quarter was up 33% compared to last year. And that includes the hedges that we actually settled on, and obviously in this quarter. So that kind of weighed on the cash flow. But the cash flow numbers are still strong at $5.89 per share for the quarter.

And even though we did have a big increase in oil and gas sales, they were up 79% to look at the income statement that benefit was offset quite a bit by the mark-to-market and the hedge results. On the oil and gas production side, we produced the average of 95 million cubic feet per day on an Mcfe basis. That’s within the range of guidance we have published back in May of this year. That’s compared to 98 million last year for the same period.

Oil production was up 22%. The gas was down 19% this year compared to last year. And when you compare these production volumes quarterly, this year versus last year, we need to note it’s important that in 2007 we had about 800 barrels of oil a day and 12 million cubic feet of gas a day related to some wells that in South Louisiana that we sold just this year. Actually in April of ’08 we received proceeds of $89 million.

So if you go back and adjust last year for that sale, then our oil production would have increased 40% and our gas production would have increased 2%.

So that kind of skews the numbers a little bit, that sale. But the sale again was used to pay down the debt. And we’ll talk about that in a few minutes here.

Again, we’ve had a lot of growth in our oil production due to the drilling in the Austin Chalk and also in the Permian Basin has been big contributors to that growth. We also hope to replace a pretty significant part of that South Louisiana production that we sold through some drilling we’re now doing ourselves in South Louisiana.

Plus we’re participating with Brigam which they’ve put out some announcements about their results. But they’ve drilled three wells. In a joint venture we have 50% of the revenue strength from those wells. And we hope to start seeing some production from those wells in the fourth quarter, so that should help kind of put us back to close to where we were. That plus our other drilling that we’re doing out in the Permian, North Louisiana and the Chalk.

We also in the quarter reported a $40 million gain on the sale of assets. $33 million of that was related to that South Louisiana asset sale. We also had a gain of $5.7 million related to selling two drilling rigs and one pulling unit. And again the total proceeds from all these sales was approximately $114 million. We paid that down in our credit facility.

Operating costs were up 28% compared to last year to $2.54 per Mcfe of production. And one thing that’s happening now, we are drilling in more oil plum regions, lifting costs are going to be higher. Also the sale of the short reserve life Louisiana properties but they were short-lived reserve life but they had costs of production. That’s kind of combined to cause this to increase.

BDNA is increased some to $2.62 per Mcfe but was within the guidance that we thought or forecasted where we thought we’d be. G&A was up 37% to $0.92 per Mcfe. Most of the increase was laid to some bonuses paid to employees that work on the sale of the South Louisiana properties.

Our expiration costs related to abandonment’s and impairments was only about $2 million compared to $24 million last year. Again the emphasis has been here of recent drilling pretty much more development wells and so we’ve had – we haven’t really had any significant dry holes in really the last six months.

Looking at the balance sheet, the financial condition of the company really hasn’t been better in a long time. Our bank debt at the end of the second quarter was $50 million. We had a borrowing base of $250 million. That leaves us at that time with $200 million of liquidity or availability under the line. We’ve also continued to pay down the debt on the join rigs on the [North Plate] joint venture and so we’re advertising that debt down. I think that debt was down to about $45 million or so at the end of the quarter, down from $75 million where we started.

For CapEx for the year we spent $155 million in the first half of the year. We are increasing our budget this year, really for the total year and the remainder of the year by $56.2 million, so our total CapEx for the year will end up being about $401 million.

This increase really is pretty much spread across North Louisiana. Again we’re drilling a Cotton [Belly Hoston] more development type wells. We’re drilling in South Louisiana, currently on some pretty good looking prospects. And then the Permian Basin picks up the difference as we’re increasing our activity out here. We’ve got some new areas that we’re going to be drilling in. So we spent – 81% of our drilling in the first half of the year was related to developmental prospects. And that’s, you know, we’re still probably for the year going to be around 75, 80% development.

And so that pretty much summarizes things from the numbers standpoint.

Mel G. Riggs

Any questions about our financial results, operating results, we can take those now and address that. And then Clayton will come back on and kind of talk about the future, an overview.

Question-and-Answer Session on Operations

Operator

Your next question comes from Steve Orr – Orr Investments.

Steve Orr – Orr Investments

On the administrative expense, its $7.9 million Mel and I think I heard you say there was some G&A bonus related to the sale of the LA property. Is that going to drop down or can we expect it up in that range going forward?

Mel G. Riggs

That bonus – well we hope there’s lots of bonuses paid for success. We hope the numbers a high number. But that was a one time event that increased. Now one thing to keep in mind, our company has a sort of different reward program where we don’t – we have not issued stock options in some time. We did the participation agreements for employees back end for interest in properties after pay outs occurred, including carrying costs.

And so we are recording a charge, a non-cash charge now to earnings – I’m sorry, to overhead quarterly to kind of cover our estimated impact of that. So what it does, it may make our G&A look a little higher, but the deletion from the standpoint of the shareholders with new shares being issued will be less. But in the second quarter – I think the third quarter – we’ll be providing guidance here in another week or so. And we’ll update kind of where we think we are. But the most – that increase was due to bonuses that were paid. One time event.

Clayton W. Williams, Jr.

I might add just to that. That was a bonus in connection with this production sale of $8 or $9 million. The people that I gave a bonus to, and it was not me, did an extra job and better than I would have thought possible and so I frequently give cash bonuses for outstanding performance. And that’s the way I’ve done and will continue to. But it is not a recurring charge.

Operator

Your next question comes from Gregg Brody – J.P. Morgan.

Gregg Brody – J.P. Morgan

I just was looking at your production performance versus your guidance and I noticed that Permian slipped a little bit. I was wondering if there was a reason for that or if that’s just a forecasting error?

Mel G. Riggs

I’ll tell you what it is, Gregg, and we looked at this pretty hard. It’s more of a timing issue. What happens on the Permian Basin – most of the wells out here have to fracted, and so there are timing issues. We get wells drilled and then we’re waiting on frac jobs. I think we’ll see – so we didn’t see the growth we expected in the quarter from the Permian. It was a little slower. But I think we’re going to see – we’ll see that catch up somewhat in third quarter.

Gregg Brody – J.P. Morgan

Are you financed altogether to see – to have people actually do the work, or is it – has it been just not [allocation] issue?

Mel G. Riggs

It’s just a busy time out here and it’s hard to -

Clayton W. Williams, Jr.

Let me add to that, if you would. In some of the new areas we’re developing, we have to test the well for some period of time. And these frac different zones. You may have heard of the [Co-mingling] or the [Wolf Berry]. So sometimes you’ll be involved in the completion of the well for three or even four months as you evaluate and be sure that you have a commercial project.

We’ve had several of those which are all good news. But you have the early expense, and yet the cash flow comes later when you put the well on production, instead of coming up to the hole to the next zone. So it’s a positive deal for the company in the future, but it’s a negative short term. That’s the best way I could answer this.

Gregg Brody – J.P. Morgan

Have you seen that across other of your areas?

Clayton W. Williams, Jr.

Well let me say that Austin Chalk, we’ve been drilling there for years. We know that fairly well. So we just have an automatic completion ongoing there. But in the Permian where we’ve come up with some new areas, the Wolf Berry is new and so there’s an element of caution that’s involved that you want to be sure that you evaluate the new wells as much as you can before you start an extensive and rapid development. So it’s a cautionary problem that you must evaluate it before you say yes, it’s commercial. And so far we’ve been very satisfied with it, but that’s the reason.

Operator

Your next question comes from Brad Evans – Heartland.

Brad Evans – Heartland

Hey, Mel, I was just curious with respect to LOE going forward. Is this a rate that we should think about on a per barrel basis? Is that reflective of what we should expect going forward?

Mel G. Riggs

Yes I believe it is. Again it’s pretty much I guess a full quarter without that South Louisiana pretty much flush production in there and we are. Because the emphasis on the oil and, you know, the Permian Basin is making up about 45% of our capital budget. And then the Chalk is – between the two of them – they’re both in kind of oily – they’re both in oil – so I think we’re probably in a little higher lifting cost environment. Unless we add some high flow rate wells in Southeast Louisiana or in the both for awhile.

Clayton W. Williams, Jr.

That would be good. Let me add this. That the Permian as a rule has a slower pay out, lower early cash flows that are longer reserve while the Chalk will come in very nice, early flows, but it will have a higher decline rate. So you’re dealing with the two that in some ways will offset each other. I think that might answer your question a little more as well.

Brad Evans – Heartland

Mel, do you have what your x rate, actually where you’re producing today? What production is today?

Mel G. Riggs

You know we’re going to provide the guidance. I’d be kind of pulling a number out of the air right now. We’ve got so much activity going on. We’ve got a lot of new wells, both in the Chalk and in the Permian. If you could give us a little time, we’ll update the guidance for the rest of the year and get you a more accurate picture.

Brad Evans – Heartland

And then lastly on the unit economics on the DD&A side, do you see – is that a good level going forward? Or do you see further opportunity to lower that as you move forward?

Mel G. Riggs

That was right in line with what we had guided for the second quarter. I think it’s a good number going forward at this point.

Operator

As there are no further questions in the queue at this time regarding this operations part of the presentation, I’d like to turn the call back over to Clayton W. Williams, Jr.

Presentation – Future Overview

Clayton W. Williams, Jr.

Well, we’re pleased with where we are. We have increased production. We’ve lowered debt. And I think Mel correctly pointed out the distortion of the mark-to-market because you’re not out that kind of money. So with that said, let me talk about – four years ago we had basically no presence in the Permian Basin. During this period of time since the acquisition of Southwest Royalties we have drilling going on in five different areas, some more mature drilling, some just commencing.

We have an ongoing confident Permian Basin operation now with improved production, with improved field operations, and certainly with new drilling opportunities. Shifting on to the Austin Chalk, that’s been a stand by. We’ve had these wells we’ve drilled the last year in inventory. I think we correctly waited to drill them until the process rose substantially. And I think we were right.

We’re going into a period where we’re going to be doing some work on the edge, and I frankly doubt that the wells will be quite as good as what we’ve experienced because the less some of these wells in the [inaudible] like a three month, four month pay out. And so we may be down to a six or eighth month and we’re doing some evaluation there.

I’m going to shift now next into the swamps of South Louisiana, the transition zone. We’ve moved into an area where we’re drilling a former dry hole and had 100 barrel a day production. I think we’re going to drill three wells and we may increase that production substantially. I can’t tell you how much because we’re in completion, but I’m happy with that.

Then go into central Louisiana. We have about as many gas wells in the [Huston] Cotton Valley to drill as we had when we started. So in that case, the Houston office has been able to add locations that we’ve drilled. And I think we’ll continue to do that. So what I’m saying about our production is basically we feel like we will continue to do a substantial amount of production development drilling. For years we did mostly wildcatting because that’s what we had to do.

Now let me flip then to our exploration program starting with Utah. We expect to split our first well in Utah in the fourth quarter, and we’re not able to tell you exactly that, but we’re comfortable we will start the first well there and probably will follow with a second.

Moving along to the Bossier now, that covers both East Texas and Louisiana. We’re re-drilling our second well in Louisiana. We’re drilling larger hole to get past that problem water flow we had. We’re hopeful about that. We have some substantial linkage, over 80,000 acres on this one possibly drilling. We have a big upside, yet there’s risk.

Let me move back to South Louisiana. We have half interest in a well that’s going through some deep mossy and sand that have high potential and there we drilled a dry hole some four years ago. Then in further exploration, the Bossier, East Texas we hope to be drilling a well there before too long. In fact we’ve planned sometime shortly after the first of the year to have three deep wells drilling in the Bossier sand for the deep Bossier that’s been so successful in the area.

I need to say, too, there’s been a lot of inquiries about the [Haysville] shale and we’ve told you that we don’t believe the bulk of our acreage in North Louisiana is potential. But we probably have maybe 10,000 acres on the Southeast edge of the Haysville shale clay that is potential. And I’m hopeful that we’ll have more to tell you about that. But at this point, that’s the most I can tell you.

So coming toward a conclusion, we have an ongoing development program in the Permian Basin. We have a continual development in Austin Chalk. We can’t tell you how much longer that will last. We have an ongoing development program in the Hoston Cotton Valley in central Louisiana. We have some development drilling and joint venturing with Brigam as Mel mentioned. And so we are very optimistic.

Our balance sheet, if you look at our debt a year ago, look at we’ve increased our reserves. We’ve reduced debt. We’re real happy with where we are and our company, I don’t think, has ever been in better shape since we went public some years back.

With that I will take your questions.

Question-and-Answer Session on Future Overview

Operator

Your first question comes from Sean Feeley – Babson Capital.

Sean Feeley – Babson Capital

How are you planning to fund the rest of your CapEx plan for ’08? And then regarding the bank facility, I think it matures in May of next year. How are you – have you started the process to replace that?

Clayton W. Williams, Jr.

We’re going to fund our drill with cash flow. That’s a nice change. We’ve done a lot of drilling over the years with debt.

Mel G. Riggs

Yes, actually it will be cash flow and some debt. And actually that loan has been renewed. We did it back in May, I believe. So it’s not a current. It’s long term.

Operator

Your next question comes from Gregg Brody – J.P. Morgan.

Gregg Brody – J.P. Morgan

What’s the maturity of that loan of the bank debt?

Mel G. Riggs

We’ve renewed it for I believe three years from November, so what would that be? 2011 or something like that.

Gregg Brody – J.P. Morgan

How many banks are part of the [inaudible]?

Mel G. Riggs

There are nine banks.

Clayton W. Williams, Jr.

Let me add I think that’s a very legitimate question. With the turmoil in the banking industry, we’re really proud that we’ve managed to get our debt down during this period of time because in the turmoil, debt can be a very dangerous thing. And so our cash flow is – our debt is like a couple months cash flow, or something like that. So I think we’re in pretty solid shape from the standpoint of the turmoil that’s ensuing and may continue to ensue in the banking industry.

Gregg Brody – J.P. Morgan

On the bank loan how is the borrowing base to be determined? Or is it the same one?

Mel G. Riggs

Yes, let me walk through that. The borrowing base up until May was $275 million. We elected – the company elected to reduce that to $250, because we don’t feel like we needed all that capacity and we’re paying for it, so didn’t use the capacity, so we dropped it - $275 to $250. It will re-determine again in November. It’s on a six month – every six months we re-determined. And we do have nine banks. The same banks have been in the credit facility for quite a – for several years now.

Gregg Brody – J.P. Morgan

So is that actually your commitment level? The $250? Or is it the borrowing base of $250?

Mel G. Riggs

It’s just the borrowing base of $250. We didn’t really push the commitment. We could get a higher commitment if we felt like we wanted to push it. But again we’re trying to – we’re really trying to operate more out of cash flow and not – we were in the process of really trying to

de-lever the company.

Gregg Brody – J.P. Morgan

You mentioned in your press release with respect to your Bossier well that you might be unable to establish production levels from these wells. And if that does not happen [inaudible].

Mel G. Riggs

Right. We’ve got both the Margarita is waiting on the pipeline hook up. The Big Bill Simpson is producing but it’s very marginal. And so we’re shooting 3D seismic in that area right now. And we’ll eventually drill another well there, more than likely. Remember [Month] Time Marathon’s our partner on part of that, actually a partner in that well.

Gregg Brody – J.P. Morgan

Is there some expectation in your ’08 production guidance that’s from Big Bill?

Mel G. Riggs

No there’s not. It’s minimal [inaudible] production.

Gregg Brody – J.P. Morgan

When you say it might force you to change or not force, recent subsequent quarters may be adversely by it affected –

Mel G. Riggs

What could happen is we could have an impairment to the well for the cost, if the well’s not commercial. And we’re going to be making that determination over the next few months.

Gregg Brody – J.P. Morgan

So it’s just about cash structure.

Mel G. Riggs

Yes.

Operator

There are no further questions in queue at this time.

Clayton W. Williams, Jr.

Thank you very much and in conclusion, we feel that we’ve never been in better shape since we started the company. We’ve reduced our debt substantially. We have an ongoing development program that in some areas have potential expansion. We’re starting to move towards some of our expiration efforts. I mentioned in particular the Bossier, which is a high potential and Utah which is a high potential. And we’re doing most of the drilling from cash flow so we’re feel pretty comfortable where we are. We’re not relaxed, but we’re optimistic. With that I say thank you for tuning in and we’ll talk to you next time.

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Source: Clayton Williams Energy, Inc. Q2 2008 Earnings Call Transcript

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