Comstock Resources Inc (CRK) 2004 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Comstock Resources First Quarter Financial Results conference call. At this time, all participants are in a listen-only mode. Later we will conduct a question and answer session.

I would now like to turn the call over to Mr. Jay Allison. Mr. Allison, you may begin.

Thank you. Welcome to Comstock Resources First Quarter 2004 Financial and Operating Results conference call. You can view a slide presentation during or after this call by going to our web site at www.comstockresources.com and clicking presentations. There you’ll find a presentation entitled ‘First Quarter 2004 Results.’ To change the page in the presentation click on the arrow on the page.

I am Jay Allison, President of Comstock. And with me this morning is Roland Burns, our CFO, and Mike Taylor, our VP of Corporate Development.

With this call I will review our 2004 first-quarter financial and operating results, as well as the results of our 2004 drilling program.

Our discussions today will include forward-looking statements within the meaning of Securities laws. While we believe the expectations in such statements to be reasonable there can be no assurance that such expectations will prove to be correct.

Page two, 2004 first-quarter highlights. Strong oil and gas prices allowed us to report a solid quarter. Our revenues reached $60.8m, and we generated operating cash flow of $37.5m. On February 25th we restructured all of our long-term debt which resulted in the recognition of a $19.6m loss, or $12.5m after tax. While the loss offset most of our first quarter’s profits it will begin paying dividends starting in the second quarter when we will begin seeing the $11m a year in interest savings.

We’re off to a strong start with our drilling program, with an 81 percent success rate despite hitting our first dry hole in the Gulf of Mexico in over a year. We’re starting our production in three of our offshore projects which should deliver an increase to our production rate starting in the second quarter.

Page three, oil and gas sales. Our oil and gas sales in the first quarter of 2004 totaled $60.8m as compared to 2003’s record setting first-quarter oil and gas sales of $68.6m. Sales in the first quarter of 2004 were down 11 percent from 2003’s first quarter due primarily to the 14 percent lower natural gas prices we realized in the first quarter. Our oil and gas sales were 16 percent higher than sales in 2003’s fourth quarter.

Page four, EBITDAX. Earnings before interest, taxes, depreciation, amortization, and exploration expense, and other non-cash expenses decreased 19 percent in the first quarter of 2004 to $45.1m, as compared to $55.8m in the first quarter of 2003. EBITDAX in the first quarter was up 17 percent from 2003’s fourth quarter’s EBITDAX of $38.5m.

Page five, cash flow, operating cash flow. Our cash flow from operations decreased 22 percent in the first quarter of this year to $37.5m from $47.9m in the first quarter of 2003. Cash flow was up 23 percent when compared to 2003’s fourth-quarter cash flow of $30.4m.

Page six, earnings. We reported net income slightly above breakeven at $25,000 in the first quarter as compared to our earnings of $20.2m in the first quarter of 2003. The first-quarter results include a charge of $19.6m or 12.6m after taxes, or 35 cents per share relating to the early retirement of our 11.25 percent senior notes which were due in 2007. Without the loss on the early extinguishment of the bonds we would have made $12.5m or 34 cents per share, which would have been up substantially from the fourth quarter of 2003’s net income of 5.7m or 16 cents per share.

Page seven, average daily production. Production in the first quarter of 2004 averaged 118m cubic feet equivalent per day which represents a two percent decrease from 2003’s first quarter and 2003’s fourth quarter. We averaged 37m equivalent per day in our Gulf of Mexico region, 30m equivalent per day in our East Texas, North Louisiana region, 32m cubic feet equivalent in our Southeast Texas region, and 19m cubic feet equivalent in our South Texas and other regions during the first quarter.

Production was generally flat except for in the Gulf of Mexico where harsh weather in January hampered production and completion activities. We expect production to increase in the second quarter as three new Gulf of Mexico platforms are turned on. We expect a substantial production gain of 18m cubic feet equivalent in the Gulf of Mexico in the second quarter.

Page eight, average prices. Average oil and gas prices. Our average oil price increased three percent in the first quarter of 2004 to $34.69 per barrel, as compared to $33.75 per barrel in the first quarter of 2003. Our average realized gas price decreased 14 percent to $5.65 in the first quarter of 2004 as compared to $6.54 in 2003’s first quarter. The lower gas price was the major factor contributing to the lower sales and profits in the first quarter.

Page nine, cost per Mcfe. Our listing cost per Mcfe produced increased 13 cents in the first quarter of 2004 to $1.18 as compared to $1.05 in the first quarter of 2003. The increase is solely attributable to additional operating costs in the Ship Shoal 113 unit in which we acquired additional interest in late 2003. We expect this rate to decrease as we are able to put on new production online in the Gulf.

Our G&A per Mcfe increased 3 cents in the first quarter of 2004 to 17 cents, as compared to 14 cents per Mcfe in 2003’s first quarter. If you include stock based compensation including employee stock options which we began expensing in the first quarter G&A per Mcfe would be 28 cents per Mcfe.

Our depreciation depletion and amortization per Mcfe produced increased 10 cents to $1.45, as compared to $1.35 per Mcfe in 2003’s first quarter. The higher rate is comparable to our fourth-quarter rate which should lessen as the new production in the Gulf comes online.

Page 10, cash margin per Mcfe. Our cash margin on a per unit basis decreased 16 percent in the first quarter of 2004 to $4.32 as compared to last year’s first-quarter cash margin of $5.14. The decrease was attributable to lower natural gas prices and higher lifting cost. The cash margin presented excludes stock based compensation which would reduce it by 11 cents in 2004.

Page 11, capital expenditures. We were very active in the first quarter of 2004 and spent $38m on our drilling program as compared to $16.3m in the first quarter of 2003. In the first quarter of 2004 we drilled 16 wells or seven net wells as part of our 2004 development and exploration program. Thirteen of the 16 wells were successful and three were dry holes. We spent $21m to drill 12 development wells of which all were successful. We spent an additional $7.7m for workovers and recompletions, offshore production facilities, and other development costs. We spent $9.3m on our exploration program. $7.9m was spent to drill four exploratory wells, only one was successful. $1.4m was spent to acquire exploratory acreage.

Page 12, our operating results per region. East Texas, North Louisiana region. Production averaged 30.2m cubic feet equivalent per day in this region in the first quarter of 2004, down about five percent from 2003’s first-quarter production rate. We drilled one successful well from the Logansport Field in the first quarter which had an initial production rate of 1.8m cubic feet equivalent per day. We plan to drill five wells in this region starting this month. We’re investigating the economics of drilling on 40-acre spacing in our East Texas fields where we have approximately 12,000 undeveloped acres. Many operators in this area are drilling on much tighter spacing than what we have.

Page 13, our Southeast Texas region. Our production averaged 31.4m cubic feet equivalent per day in 2004’s first quarter in this region, which was up around four percent from production in the 2003’s first quarter. We’ve recently completed and tested our fifth successful Woodbine producer in our Double A Ross prospect area in Polk County, Texas. The Davis-Blackstone No. 1 was drilled to a depth of 14,850 feet and found 33 feet of net pay. This well was drilled to test the northwestern extent of the Ross Woodbine Development. We expect this well to produce at a rate approaching 8m cubic feet equivalent per day by mid May. We have a 48 percent working interest in this well.

We are in the process of obtaining 3-D seismic data over the Ross and [Robin] [ph] area and plan to drill an exploratory well south of Ross but north of Robin this year. We anticipate receiving the seismic by late July, and thereafter, start interpreting it. We hope to drill the Robin prospect this year but timing is contingent upon obtaining a drilling permit from the Park Service. In addition to the exploratory activity we plan to drill two additional development wells in this region this year.

Page 14, South Texas and other regions. Our production averaged 19.1m cubic feet equivalent per day in 2004’s first quarter and our South Texas and other regions area, which was up approximately 37 percent from production in this region in 2003’s first quarter. We drilled five wells in South Texas in the first quarter. Our two exploratory wells were not successful, including a well testing our Wadsworth prospect and the first test well at Armstrong Ranch. We did drill another successful well at Ball Ranch in Kennedy County, Texas. The Clark-Sain No. 10 was drilled to a depth of 15,410 feet and found 110 feet of total net pay in the Vicksburg formation. The well’s initial completion flow tested to sell that 9m cubic foot equivalent per day. We have a 20 percent working interest in this well. We also had two successful development wells with the Lopez No. 2, and the Macon No. 114, and the JC Martin Field. We currently have five rigs drilling in South Texas and plan to drill another 10 wells in 2004.

Page 15, our Gulf of Mexico region. Our production averaged 36.8m cubic feet equivalent per day in 2004’s first quarter in our Gulf of Mexico region, which was down 12 percent from 2003’s first quarter. We drilled nine wells or four net wells in the Gulf of Mexico in the first quarter. All but one of the offshore wells were successful. The one dry hole was drilled to test a prospect in South Timbalier, Block 16, in which Comstock had a 33 percent working interest. During the first quarter we drilled our third successful appraisal well at South Pelto 22, we also successfully sidetracked a well at South Timbalier, Block 11, and we drilled a second successful well at Vermilion 122. We reported on these wells in our February conference call.

Since that date we have drilled our third successful well at Vermilion 122, a second successful deep exploratory test at South Pelto Block 25, and a third successful well at Vermilion Block 51. The second well drilled at South Pelto Block 25, the OCS-G 14535 number six well was drilled to a depth of 16,748 feet and found 53 feet of net productive pay. We have a 24.9 percent working interest in this well which is now completed and waiting on a final connection to the processing platform.

During the first quarter we have drilled and completed two additional wells in our Ship Shoal 113 unit. The OCS-G 00069 No. 23 well was drilled to a depth of 11,219 feet and found 151 feet of total net pay in six reservoirs. This well in which we have a 90 percent working interest is completed and is producing 2.4m cubic feet equivalent per day of natural gas. The OCS-G 00066 No. 01 well was drilled to a depth of 12,234 feet and found 180 feet of total net pay and four reservoirs, and is producing 4.1m cubic feet equivalent per day. We have a 72 percent working interest in this well.

We plan to drill 15 more offshore wells during the rest of 2004. We currently have four rigs active in the Gulf of Mexico area. Two are drilling new wells, and two are completing existing wells.

Page 16, the Gulf of Mexico connection timing. Three of our offshore projects are coming online in the second quarter, and two others should start up in the third quarter. Production has started up at South Pelto Block 22 where three wells have been completed and connected to the South Pelto 22 processing platform. The OCS-G 18054 or the No. 3 well was the first well to be turned to sales on April the 13th, and is flowing approximately 1,200 barrels of oil and 4m cubic feet equivalent of gas.

The OCS-G 18054 No. 2 initial discovery well and the OCS-G 18054 No. 5 wells have not yet been turned to sales due to the need to optimize the processing platform operations. We expect that the gross daily production from the three wells should approach 35m cubic feet equivalent per day, and that all three wells should be flowing to sales by mid-May of 2004. We have a 29 percent working interest in the South Pelto Block 22 wells.

South Pelto Block 25 is also starting up production. The initial discovery well is completed and connected to the nearby processing platform. The discovery well, the OCS-G 14535 No. 5 well was first taken to sales on April the 16th of 2004 and is flowing approximately 1,700 barrels of oil and 1m cubic feet of natural gas per day. We expect both wells of South Pelto 25 to be flowing to sales by early June at a combined rate approaching 20m cubic feet equivalent per day. We have a 24.9 percent working interest in the South Pelto 25 wells.

Vermilion Block 121 which includes three wells is also starting up production operations. The OCS-G 22620 No. B-1 and the OCS-G 22620 No. B-2 wells were both turned to sales on April the 29th of 2004. These two wells are currently flowing approximately 9.9m cubic feet equivalent per day. We expect the third well, the OCS-G 22620 number B-3 will be turned to sales by the second week in May. The production from all three Vermilion 122 wells should approach 20m cubic feet equivalent per day by the end of May. We have a 40 percent working interest in the Vermilion 122 area. We expect Ship Shoal 109, 110, and Vermilion 51 to come online in the third quarter.

Page 17, offshore prospect inventory. In the recent Federal lease sale we were the successful bidder for eight blocks containing approximately 38,000 acres. Not including our projects at Ship Shoal 113 and South Pelto 22 and 25 we have 149,000 acres of unexplored acreage in the Gulf of Mexico under lease. We estimate that these leases have prospects that are targeting roughly 1.3 trillion cubic feet of gas.

Page 18, capitalization. Our capital structure. At the end of the first quarter we had a total of 339m in total debt. We had 142m outstanding under our new bank credit facility which has a borrowing base of $300m. Our stockholders equity was $293m at the end of the quarter giving us a 54 percent debt to total capitalization ratio.

Page 19, debt restructure. On February 25th we completed restructuring our long-term debt to take advantage of the current low interest rate environment. We repurchased 90 percent of our expensive 11.25 percent bonds on February 25th and the remaining 10 percent were repurchased three days ago, or on May the 1st. We sold 175m and six-and-seven-eighths percent senior notes which are due in 2012, and entered into a new $400m bank credit facility with an initial borrowing base of $300m. The result of the restructuring is a reduction in our interest expense of 36 percent on a pro forma basis and a lengthening of our maturities from an average of 2.4 years to 5.9 years. Our interest expense per Mcfe falls 25 cents to 43 cents on a pro forma basis, from 68 cents last year.

Page 20, 2004 outlook. Our outlook for the rest of the year. We still expect to spend $110m on our development and exploration program this year. We currently plan to drill 61 wells in 2004. Our exploration program will be fed by our substantial inventory of drilling prospects in our Gulf of Mexico, South and Southeast Texas regions. We expect our production to begin to increase in the second quarter as we are able to hookup more of the offshore discoveries that we have made. The second quarter will also start seeing the benefit of our February 25th debt refinancing. And lastly, with continued strong natural gas prices we should generate substantial cash flow in excess of our capital expenditures starting in the second quarter which we will use to pay-down our debt.

The only update to that would be on our production in the Gulf of Mexico at South Pelto 22, we received information this morning that the No. 5 well was just turned to sell this morning. And the South Pelto 22, the No. 2 well which was the initial discovery well is expected to flow to sales later today. So we expect all of our production at 22 to be on by late today.

So with that, let me turn it over for questions, please.

[Caller instructions.]

Our first question comes from Ray Deacon from First Albany Capital

The program for the remainder of this year, how much of that is built into your, you know, well, where do you think at this point production is going to be up for the year? And how much of the exploration is built into that number?

Yes, Ray, I guess your question was on the – yes, where we think kind of production outlook will be for this year, we still have the same kind of range of guidance of a 10 to 15 percent increase in the year. Yes, I think we’re probably, we were probably three to four weeks behind on actually getting the Gulf of Mexico production online. And so I would say that we’re, I mean, based on that, looking at future exploration to add to production at all, we’d probably fall right in the middle of that range right now. The current production is over 130m a day, and we should be in the 130’s, you know, for the second quarter.

Okay.

And then continue to build on that, Ray.

Right.

And I think, Ray, if you look at like South Pelto 22, I mean despite the delays that we’ve had which are strictly due to weather, I mean I think we’re pleased with the initial performance that we’ve seen. If you look at the No. 3 well, which is the first well to be turned to [sells] [ph], which is only on April the 13th, and it’s about, you know, 1,200 barrels of oil per day and 4m a day of gas.

And just this morning did we receive a report that the No. 5, well which is the last well drilled at Pelto 22, that it was turned to sales I guess yesterday. And the No. 2 well which is that initial well, it should start flowing today. They have, you know, they’ve tested the flow lines on that, and it should be producing today. And so we are pleased that all three of those will be producing now versus, you know, we continue to be – to have waited on the production, and now actually we’ll see the sales.

Okay. And how many other fault blocks do you think are prospective on South Pelto 22, or will you be able to test any of those this year, I guess?

Well, when we initially drilled the first well, I think what we said is we didn’t really know how many fault blocks we have tested, but I think two of the fault blocks right now, maybe three, we’ve tested three of those with this last well.

Right.

And, you know, in our opinion I think that there’s probably two more fault blocks that we still need to be testing. Mike, might comment on that?

Well, we have a number of faults that would present exploration targets that we haven’t considered on our, on any current production forecast or reserves. But it’s an interesting block, Pelto 22, of course is adjacent to Pelto 23. And the same zones that produced in Pelto 23, are our targets in 22. And so we have a few more targets.

Okay. And I guess I just was trying to get at, you know, a number of the exploration wells you’re drilling this year are located immediately next to infrastructure. And, you know, is the activity in the Gulf front-end loaded so that if you are successful you could get some of those volumes on this year and the guidance might go up? Or is a lot of it going to be later in the year?

Well, what we’ve said is we only plan to drill one well this year thus far that if it were successful we would not be near an existing production facility, so we would have to set the platform.

Right.

All the rest of the wells we, you know, we anticipate would be near existing facilities.

Okay, great. And just two quick numbers questions. I guess Roland, what’s the run rate for interest expense per quarter? I was thinking around 4.5m, does that sound about right?

Right. That’s, yes, 4.5m is a good number. And then as we – I think we’ll start reducing our bank debt, you know, starting in the, you know, second quarter and third quarter.

Right.

The cash flow exceeds what we expect it to be, our capital expenditures will be less than our cash flow. So that 4.5 would be the highest number, and then it should start coming down a little bit as we pay-down some of the bank debt.

That’s great. So, and interest expense, I mean in exploration expense would you go back to kind of one to two, do you think the next couple of quarters?

Yes, I think we had a lot of exploration expense in the first quarter, which was unusual.

Right.

But I think, you know, $2m is kind of more of what we would expect. I think we just had, we also had quite a lot of seismic in the quarter. You know, both offshore and in the Double A wells area. And then we had the dry holes in South Texas and the Gulf of Mexico dry hole so --.

Okay, got it. Okay, thanks a lot.

All right.

Our next question comes from Ron Mills from Johnson Rice. Please go ahead.

Good morning, guys.

Hello.

A question just to follow-up a little bit on South Pelto 22. Just the first well that you brought online, how do you expect that performance to be relative to especially the discovery well which had a lot more pay than did the second two discovery wells?

Yes, the first, the initial discovery wells had all the pay in the big zone. I think the first well, you know, is predominantly an oil well, and maybe so I think with that oil production that they are producing at a lower rate than what they thought they would as a gas well. They’re going to just monitor that and see where they really want to produce it at.

And so we probably think there’s probably two oil wells out there, and then the initial discovery well, you know, hasn’t flown yet but you know they still think that’s probably going to be a gas well. We’ll know in the next week or so, really how they all look, and then it might be another several weeks before they really choose at what type of flow rates they think that, you know, is the proper way to produce them.

You know, what they did on the No. 2 well, Ron, is they hydro-tested or pressure tested the equipment, you know, to make sure that there were no problems with it. And then once that was successful then, again today, they should or expect to flow that well to sells today.

You have, you know, an issue of reserves, too, maybe. If you look at oil and you look at quantities of oil, and the value of oil versus the quantity of gas, and the value of gas, the same type reservoir. You know, usually oil is a lot more valuable if it’s in the same volume. And so, you know, we’re kind of recessing that, too. Because the No. 5 well is definitely, or the No. 3 well is definitely an oil well at 1,200 barrels a day and 4m a day of gas.

Okay, and I guess what I’m trying to get a sense of is on one of your earlier presentations you had the forecast of kind of that 40m to 45m a day. Is that ramped down to 35m gross primarily a function of the oil production versus gas, or is the 35m kind of the number you want to talk to and hopefully be able to talk about that being higher going forward?

Well, I think it’s a lot, definitely probably because it’s oil. I mean they’re going to – I think that’s still kind of – unknown exactly what the proper flow rate, you know, that they want to produce the three wells at, but that’s just our best guesstimate, you know, given what little activity there’s been so far.

And how long do you think it’ll take to get to the optimal rate? I’m sure this is something that happens over a portion of weeks and not days, is that fair?

It took about three weeks to get the No. 3 well, I mean kind of smoothed out as far as production. And you anticipate probably the same timeframe for the No. 5 well then the No. 2 well.

Yes, we were basically saying mid-May.

And so that’s kind of why we say mid-May.

Okay. And Roland, did you say then that the second-quarter production, where you’re currently above 130m but you’re expecting the guidance for the second quarter to be at that 130m, or above? Or is that a little bit optimistic?

Yes, we think that 130 – yeah, in the 130s, 130 to 133 or something is a good, achievable number for the third quarter.

For the third quarter?

Second quarter, I’m sorry. Yes, the third quarter should be better than that.

And Ron, we’re a little north of 130 right now. And, you know, if we were 118 in the first quarter, so that was low. And so we’re up, you know, 12 or 13m a day from that, and that does not include production from, of course, the No. 5 well or the No. 2 well at South Pelto 22, so.

Okay, and Roland, I may have just misunderstood or I just want to clarify, you had the 18m a day to add in the second quarter which it sounds like some of that has come on. But was that net to you all?

That’s net, but that’s the amount of new adds, not necessarily there the whole quarter, but that’s the new production, right, that is coming in in the month of, you know, May really.

And it won’t be, Ron, we won’t have it for the full 90 days. We’ll have it for part of the quarter.

Right. And in South Texas especially with the two dry holes down there, what is you all’s plan going forward in South Texas beyond the development of Ball Ranch and your current discoveries?

Well, we had a deep prospect in Armstrong, and that did not work out. We do have some shallower prospects, we will continue to drill those. And we’ll continue to be active in the other counties plus the Ball Ranch area.

Okay, in East Texas where do you – what’s most of your current spacing on most of your acreage up there?

Right now, I’d say anywhere from 100 to 160 acres for most of it. Some of our leases are drilled-down in the 80-acre spacing in some of the better areas.

Okay. And does the Robin prospect may or may not get drilled this year, but did you say that you do expect to drill a well between Ross and that Robin prospect after the 3-D seismic?

Right, we think where we call the North Robin prospect is going to be drillable from outside of the big thicket and, you know, based on the seismic evaluation we think that’s definitely something we can drill this year. And then the Robin will be, you know, depending on the, you know, permits, and also the seismic.

And the current status, Ron, of the seismic as of this morning is it was three weeks late because, of course, weather delays. And we should receive that in mid-July and start interpreting it the latter part of July, and that was as of this morning. And so that’s, I think that’s pretty good.

And you currently have 100 percent interest in that well? And are you still planning on waiting until the evaluation of that seismic to decide your ownership?

Yes.

All righty, thank you very much.

Thank you, Ron.

[Caller instructions.]

We have Ron Mills online with a follow-up. Please go ahead.

No one else is out there. The South Pelto 25, you know, first of all, it looks like it came on pretty strong and then with the addition of the second well probably a little bit above what you had thought, what is, what’s going to take a month to – or what’s the one month hookup time for the second well at Pelto 25?

Well, you know, that well has just been drilled and completed, so it’s actually …

It’s a flow line.

Yes, we actually think that’s almost like a record time hookup, so actually …

That’s a very new well.

We just finished drilling it, and actually it’s going to be a quick connect compared to the normal timeframe out there.

Now, that well, as you know, was drilled in the first quarter. And I think there was a little over 4,000 feet of flow line. And you know, we think it’ll be flowing to sales by really June 1st is our goal.

And so both of those wells, you know, we hope to have both of those producing a little over 20m a day equivalent is our goal. And we own a little less than 25 percent working interest in those wells.

And in that area we’ve got, we do have about a 120-day drilling provision, that once you’ve moved a rig off you’ve got 120 days to spud another well. And so we’ll drill several more wells in that area this year.

Okay. And Roland, from a model standpoint with the production paths moving up in the – at least on a unit basis in the first quarter, do you expect on a unit basis for that to trend back closer to the $1.05 to $1.10 range?

Yes, we do. You know, really especially in the third, fourth quarter, and a little bit in the second quarter, that with the newer production on, you know, we should be able to spread that fixed cost over more volumes and so get it down closer to the, like you said, $1.05 level.

Okay, and then there was the G&A, is the 3m or so a quarter a pretty good run rate including the stock options?

Right, I think that’s a good number. You know, including the stock based compensation which was – we adopted that on a modified perspective basis, so we’re – the prior years you’re not being restated to reflect what stock based compensation would have been, but we just really, you know, picked it up here in the first quarter on a go-forward basis.

And is it expected to be about that 1 or 1.2m a quarter?

Right, for this year.

Okay. And finally, continue my monopoly, the capex of 38m in the first quarter obviously that’s, you know, a little bit more than a third of what your full year capex is?

We had a lot of activity, we would see that coming down a little bit. In fact, you know, the $25m level a quarter, you know, starting with the second quarter. I think, you know, into a lot of the facilities putting it in place, a lot of rigs going, and so it was a very busy quarter so we think that’ll come down a little bit but we’re not really changing our projection of our total budget at this time.

And is the expectation then to the extent that we have anything above that 110 for most of that to go to debt reduction, or is there potential especially as we get into the second half of the year for some prospects to be added especially as blocks get awarded from the lease sale?

Oh, there’s – the immediate plans are to start paying down some debt in the second quarter. And I’m sure that’s what you’ll see at first. There might be some potential that, you know, if we start out the East Texas, you know, drilling program beyond the wells that we did start, because they were budgeted, then we’d have to come back and look at a higher budget but we haven’t really made that decision. It might be really more toward next year that we really get that all in place.

And in East Texas are you drilling, are those what you would plan on targeting as some of these Cotton Valley sands that kind of has swept the street, where you know kind of tight gas sands plays, or are these – what formations are those?

Ron, those are primarily Cotton Valley wells in Harrison and [Roscinow] [ph] County area. We have a couple of leases there in particular that we’ve targeted as candidates for down spacing.

Okay, thank you very much.

Ron, one other thing on our production. We’ve kind of overlooked this Vermilion Block 122. Remember, we’ve drilled three wells in that area. The B-1 and the B-3 wells were both turned to sales just recently, April the 29th, and they’re making about 10m a day equivalent, and we own 40 percent of that. But then the third well which is the B-2 well, we expect it to go to sales somewhere around the 7th or 8th of May, and that should be another nice well. And overall, in Vermilion which is a pretty big block for us, I mean we’re looking at about 20m a day of production from those three wells.

Okay. All right. Thank you very much.

Thank you, Ron.

Our next question comes from Pavel Molchanov from Raymond James. Please go ahead.

Hi. Yes, just a question or two, to follow-up on your discussion of debt. What do you think is going to be your debt to cap by the end of the year? I know you guys are currently at roughly 54 percent which is actually up slightly from yearend. Do you think you’ll breakthrough 50 percent by yearend?

Oh, yes, we feel like we’ll, you know, really get down closer to, you know, the 45 percent by the end of the year. The number is really up in the first quarter because of the restructuring of the debt where we paid the premium to buy the bonds back. And, but you’ll start really seeing in the second quarter where we go back to paying down debt, and should be able to pay down if gas prices, you know, stay up where they are, pay down a nice amount of debt and get the debt to capital below 50 percent. Hopefully, maybe by the third quarter be at that level.

Yes, understood.

[Caller instructions.]

We do have Ray Deacon online. Please go ahead.

Yes, hey, just one question on Ship Shoal 113. What’s been the success rate since you farmed that out? And do you still have further locations to drill there?

We’ve drilled four wells, and of course, we bought interest from Murphy and then bought [Valast’s] [ph] interest available from Conoco, and own most of that. So we’re 100 percent on the wells that we’ve drilled. And they were development wells, and we have some more targets to drill this year, and we’re looking at a deeper exploration potential there on the blocks, as well. That’s nine contiguous blocks with infrastructure, and we think there’s a lot of opportunity there.

And we initially, Ray, you know we had about 12 prospects and we reprocessed all of that data last year in the first three quarters, and we came back starting in the fourth quarter and drilled two wells and then we drilled two more in the first quarter of this year, and we're drilling a well right now, and so we’re going to keep a rig busy out there.

Okay, great. And talking about service costs, you have two rigs locked up through yearend, is that right? I mean would you look to extend that into next year? Are you seeing the market getting tighter at all now, or about the same, or?

Yes, I think we have two rigs under a longer term contracts, and for those particular rigs I guess we haven’t seen a big change in the market.

Right.

You know, I think we, you know, typically we don’t like to go out more than a year. And we only extend on those when they come closer to expiration.

Okay.

As probably as many rigs as they want to have on a longer term commitment. The other ones I think were, you know, maybe one or two well type commitments on those.

Okay, got it. Okay, great. Thanks.

[Caller instructions.]

Gentlemen, at this time I show no further questions.

All right, I guess as a final comment, again, as Roland said, we do expect production to increase 10 to 15 percent in ’04. And currently, you know, where we are versus first quarter, our production is up. Our interest expense is down, commodity prices are up, we’ve got nine rigs that we’re using both onshore and offshore, seven are drilling wells and two are completing. And we plan on continuing to paydown our debt this year, and so we look forward to a good second quarter. Thank you.

Thank you.

Thank you. Ladies and gentlemen, this will conclude today’s teleconference. Thank you for participating, you may now disconnect.