Comstock Resources Inc (CRK) 2002 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome of the 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. Good morning, everyone. Welcome to Comstock Resource's first quarter 2002 financial and operation results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and clicking presentations. There you'll find a presentation entitled first quarter 2002 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 Chief Financial Officer and Mike Taylor, our Vice President in Corporate Development, who will help answer questions this morning.

With this call, I will review our first quarter 2002 financial results, as well as the results today in our 2002 drilling program. As you know, our discussions today will include forward-looking statements with the meaning of the securities laws. While we believe the expectations and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

If you would now, on Page Two, first quarter 2002 highlights. On the call today, we're going to look at our first quarter 2002 financial results, which were much lower than the record-setting first quarter we had in 2001. The decline in revenues, cash flow and earnings from 2001 were mostly driven by lower oil and lower natural gas prices. We did show a 14 percent production gain for the fourth quarter last year due the DevX acquisition. Expected production gains in our Gulf of Mexico region did not materialize in the first quarter as timing delays and significant shut-in time offset the new production added at our South Tim 34 well. our offshore production is up significantly so far in the second quarter as a result of two successful wells drilled, one at South Pelto 5 and the other in South Tim 34. Jointly these wells add 28 million cubic feet equivalent per day of production to our interests is 29 percent of that. And, lastly, we continue to have excellent results in our drilling program where we have 10 successes out of 11 wells drilled today so far in 2002, including the two high-volume wells in the Gulf of Mexico, being the South Pelto 5 well and the South Tim 34 well.

Page Three, revenues, our first quarter's revenues were down 60 percent from 2001's first quarter due to the substantial drop in oil and gas prices. Revenues in the first quarter total $26.8 million, as compared to $67.4 million in 2001's record setting first quarter. Revenues were up 9 percent from our fourth quarter revenues, at $24.5 million. EBITDAX, Page Four, earnings before interest, taxes, depreciation, amortization and expiration expense and other non-cash expenses, including derivative mark to market adjustments, and gains or losses on property sales or EBITDAX decreased 68 percent in the first quarter to $18.1 million, as compared to $57.1 million in the first quarter of 2001. EBITDAX in the first quarter was up 19 percent from fourth quarter EBITDAX of $15.2 million. Page Five, operating cash flow, our cash flow from operations fell 77 percent in the first quarter of this year to 11.3 million from 49.2 million in the first quarter of 2001. Operating cash flow was also down 13 percent from fourth quarter cash flow of $13 million. On a per share basis, cash flow from operations decreased 76 percent in the first quarter to 33 cents from $1.40 in the first quarter of 2001 and decreased 6 cents from 39 cents in the fourth quarter of 2001. Page Six, earnings, we reported a net loss of $3.1 million in the first quarter, as compared to earnings of $23.6 million in the first quarter of 2001. The $3.1 million loss is before a non-cash $2.4 million derivative mark to market loss and a loss from discontinued operations of $768,000 relating to certain marginal properties we sold in April of this year.

The first quarter loss was slightly less than our fourth quarter loss of $3.6 million. We had an 11-cent loss in earnings per share in the first quarter, as compared to income per share of 68 cents in 2001's first quarter.

Page Seven, production, production in the first quarter averaged 115 million cubic feet equivalent per day, which represents a 4 percent increase from 2001's first quarter, and a 14 percent increase from 2001's fourth quarter. We averaged 36 million cubic feet equivalent per day in East Texas, North Louisiana, 31 million cubic feet equivalent per day in Southeast Texas, 33 million cubic feet equivalent per day in our Gulf of Mexico region and 15 million cubic feet equivalent per day in South Texas and other regions during the first quarter. Production met our expectations in all regions in the quarter except the Gulf of Mexico where expected production gains did not materialize until the later part of March and April. And, these production gains were offset by substantial down time as facilities were being modified. We expect a substantial production gain of 8 to 10 million a day in the Gulf of Mexico in the second quarter. Page Eight, oil and gas prices, the fall in oil and gas prices account for declines in revenues, cash flow and earnings this quarter. Our average gas price fell 68 percent to $2.37 per Mcf from $7.47 per Mcf in the first quarter of the year 2001. Our first quarter gas price also decreased 5 percent from the fourth quarter gas price of $2.49.

Our average oil price in the first quarter declined 27 percent from $28.19 in 2001's first quarter to $20.67 in the first quarter of 2002. As compared to the fourth quarter of 2001, our average oil prices increased 6 percent from $19.43.

Beginning in the second quarter we had approximately half of our natural gas production hedged at $3.46 per Mcf. Page Nine, cost per unit of production, our lifting cost per Mcf produced decreased by 16 cents in the first quarter from 95 cents in 2001 to 79 cents, due primarily to lower production taxes related to lower oil and gas prices. Lifting costs decreased by 2 cents from 81 cents for the fourth quarter of 2001. Our G&A per Mcfe increased to 9 cents in the first quarter from 8 cents in 2001, due to increases in personnel costs in 2002. G&A expenses per Mcf were down significantly from the fourth quarter G&A expense of 21 cents per Mcfe.

DD&A per Mcfe produced has increased by 11 cents in the first quarter to $1.28 from $1.17 in the first quarter of 2001. DD&A per Mcfe decreased by 7 cents from the fourth quarter of 2001 of $1.35. Page Ten, cash margins, our cash margin on a per unit basis fell by 70 percent in the first quarter, compared to last year's first quarter. Due to low prices, our cash margin decreased to $1.70 per Mcfe this quarter, as compared to $5.74 in 2001's first quarter. Despite lower prices in the first quarter, our cash margin increased 4 percent from the fourth quarter cash margin of $1.64 per Mcfe due to lower cost in the first quarter. Page Eleven, capital expenditures. In the first quarter of this year we spent $15.7 million on our drilling program in response to lower oil and gas prices, we cut back our drilling expenditures significantly. We spent $5.7 million to drill eight development wells, all of which were successful. We spent an additional $1.4 million for workovers and recompletions and for production facilities. We spent $8.6 million on our expiration program, which was over one-half of our total expenditures. 2 million was spent for exploratory acreage. 6.6 million was spent to drill three exploratory wells, two were successful and one experienced a mechanical failure.

Page Twelve, capitalization, our balance sheet. At the end of the first quarter we had $378 million in total debt. We had $158 million outstanding under our new bank credit facility, which has a $240 million borrowing base. On March 7, we sold a $75 million add-on to our senior notes and reduced our bank borrowings by $75 million. We now have over $80 million available under our new credit facility.

We ended up with $211 million in book equity at the end of the quarter.

Page Thirteen, our drilling results. First, our drilling results in our East Texas, North Louisiana region. In the first quarter of this year, we spent $4.6 million drilling seven wells, or 2.7 net wells, all of which were successful. All of these wells were drilled in the Gilmer field that we acquired in the DevX acquisition December of last year.

An additional 14 wells are planned at Gilmer for the remainder of this year. Page Fourteen, the Gulf of Mexico regional results, in our Gulf of Mexico region we spent $9.3 million in the first quarter. We made two significant discoveries this quarter in our exploration program with Bodark Offshore [phonetic]. We drilled another successful well at South Pelto 5 and one at South Tim 34. These wells had an initial production rate, which averaged 14 million cubic feet of natural gas equivalent for each well. We have a 25 percent interest in the South Pelto 5 well and a 33 percent interest in the South Timbalier 34 well. these wells were recently connected to sales in the second quarter. We had a $2 million write-off on an exploratory well drilled at South Timbalier 30 in the first quarter. We initially discovered 43 feet of pay sand in this well when we lost the well, while drilling to a deeper target. We plan to redrill this well in the future pending the results of under exploratory activity in this block.

Page Fifteen, second quarter exploration. In the second quarter we have eight exploration projects underway, which could have a material impact on the success of this year's drilling program. So far, we have had some early success and no failures. We're just completing drilling of prospect at Ship Shell 67 [phonetic], which is now being logged, which has a reserve target of 13 Bcfe, which looks very promising.

Next we plan to drill an 11,000-foot test at South Pelto 1, which has a target of nine to 10 Bcfe. We have a 50 percent interest in both of these wells. In the South, the Double A Wells field we are drilling the Hammond Number 1 well, which is a 15,200-foot exploratory well targeting 9 to 10 Bcfe reserves in the upper wood bine sand [phonetic]. At the Ball Ranch in South Texas we have hit our second successful well, which should have approximately four to five Bcfe reserves that happened several weeks ago.

We plan to drill another well at Ball Ranch in the second quarter , which will have the same reserve target. We have a 20 percent interest in the Ball Ranch wells. In Golliet County in South Texas we are drilling a 16,000-foot well to test the Wilcox at our ChartCo [phonetic] prospect, which has a reserve target of 25 Bcfe. We have a 17 percent in this well. And, lastly, we plan to drill two other South Texas prospects in Starr County, the Lopez and the Pina prospects, which have reserve targets of 5 Bcfe per well. We have a 65 percent interest in these prospects.

Page Sixteen, outlook for 2002, despite the weaker natural gas prices we've had in the first quarter of this year, we are very excited about the growth of Comstock. With the DevX acquisition and new production coming online in the Gulf of Mexico, our target for production this year is 45 Bcfe for an increase of 21 percent over 2001's production. We plan to spend $75 million to drill 49 wells this year and we may increase that amount if the recent strength in gas prices holds up. We have substantial upside in our multi-year inventory of drilling prospects Gulf of Mexico and South Texas. And, lastly we have substantial financial flexibility in place this year to weather low gas prices. Our drilling program will be funded out of operating cash flow, which has been shored up by our decision to hedge approximately half of our natural gas production through October at a price of $3.46 per Mcfe to ensure that we can cover our drilling expenditures.

We also have over 80 million of availability on our new revolving credit facility to provide additional liquidity if needed. With that, I would like to open it up for questions.

Our first question comes from Chris Miller from Morgan Stanley. Please state your question.

Good morning, guys. My first question is I know what your target is production for the year, but I'm looking at the second quarter, the two new wells in the Gulf of Mexico, if I look at quarter-to-quarter should that, you know, add about, you know, 7 to 10 Mcf a day?

Chris, we're looking for that production to add, you know, anywhere from 8 to 10 a day.

Yes, those two wells are probably six, but then there's also downtime and other things that were happening at Ship Show that are being corrected and South Tim 34 getting up to full speed. We're expecting at least a 10 million a day increase and most of that we already have now. So, that's the type of increase, you know, we're projecting for the second quarter.

It looks like you're having, you know, good drilling success in the Gilmer Field. What is production look to do that over the next several quarters?

I'll let Mike answer that. What we've done, Chris, from Gilmer, as you know, we said we drilled 21 wells; we'd keep three rigs busy through the end of the second quarter. We've drilled seven wells so far. If you look at what we've done on those seven, those in Q1 for the wells tested the Smackover, so we've deepened those wells by another 600-feet. And, our cost for that is an additional $125,000. We've completed one of the four Smackover deep test and we're testing three others. They're shut in for reservoir pressure buildup. And, we're doing now, we've -- we plan on drilling the second quarter we'll probably drill six additional wells there and five of those six have been drilled already using the three rigs. And, then we'll go to a one-rig program the later part of this month and we'll keep that one rig busy the rest of the year. That will get us through our 21 to 22 wells that we'll drill. And, we've completed four of the seven that we drilled in the first quarter.

The results, Mike, you want to go to the results?

Well, what we've had so far we've -- currently what's going on there, we have eight wells that are drilled and -- this is not just first quarter, but just cumulatively for the year that have not been put online yet. So, we haven't seen the effect of that. We've got two additional wells that were recently just put online. We currently have three wells drilling and we've got a location being build. So, there's a lot of activity there. We would expect, I think in the second quarter, probably to see, second through third quarter, to see an uptake of anywhere from five to 8 million a day out of the new wells and the additional drilling that's going on there.

The typical well, Chris, it'll -- it comes on at 1.5 to maybe 2 million a day. But, the wells come in and they ramp up to their maximum production in a couple of months and the reason it takes about 60 days to really ramp that production up is that we have 1 to 1.1 million pounds of prack [phonetic] and that's a gel prack and it takes that long to clean it up. You got about a 9,000-pound bottom hole pressure. So, I mean it does clean up, but you'll see maximum production within 60 days after it's hooked up. But, you've not seen any of that in first quarter. You'll start seeing that in the second quarter because--.

Mostly in the third quarter, Chris, is when, you know, that's kind of how we've seen -- expect the East Texas production to really show, you know, that increase. At that time, those are really into sales.

Each one of these wells when it reaches its maximum initial potential is anywhere from 600 to 800 net Mcf a day to us. So, that's kind of the scale of things. And, of course, these things will not all come on at the same time and they'll be declining while others are coming on. So, it's kind of a moving target, but that'll give you a feel of the magnitude of each one of these wells.

And that excludes a success that we may or may not have on the Smackover.

Okay, that's perfect. That's what I was looking for. My last question really is if you look at where gas prices are and with your capital budget you mentioned you might take that up. You clearly are throwing off a lot of cash. How are you thinking about what you're going to use that cash for and if you do take the capex budget up, what do you think, you know, the first couple projects might me?

I think, Chris, on the -- right now we're still leaving the budget where it has been and, you know, would use the additional cash flow to reduce the debt level that the company has. Although, the first projects that we're looking at to maybe bring into the budget and this would be in the second part of the year, second half of the year, would probably be at Double A Well's field to go in and if gas prices are strong to do the development of the interior of the field where the Indian reservation is. Some of those wells would be accelerations wells, others would add new reserves. But, that's got -- it's probably the area that we would like to target. And, would have the biggest impact on production.

Remember, we have 11 locations that were in leases that are involved in the Albama Coshoda [phonetic] litigation. We own about a 37 percent interest in those prospective wells. And, we would take a look at drilling those wells if, one, the litigation is settled and, two, gas prices stay where they are.

Excellent. Thank you guys.

Thank you, Chris.

Our next question comes from Megan Wudaso [phonetic] from King Capital Management. Please state your question.

Hey, guys how you doing?

Very good.

Good. I just want to -- I got -- I jumped on here a little bit late. You said that -- could you review the outlook, you gave the estimate and the outlook for 2020 total production?

What we're looking at in 2002 is we're saying that with the DevX acquisition and the new production coming online in the Gulf of Mexico, which we've got South Pelto 5 and South Tim 34, that's come on recently, our target for production this year is 45 Bcfe for an increase of, you know, 21 percent or so in 2001. And, what that depends upon, really, is that if we've stuck with the $75 million capex budget and that assumes that we drill 49 wells this year and that we could increase that if gas prices stay higher. And, again, we did hedge for six months, which is April through October, at this $3.46. so, we're just staying with the 49 wells with Gilmer coming on as it is. And, with one rig busy in the Gulf of Mexico that we would have 45 Bcfe or 21 percent increase.

Okay. And, so there's some assumptions that that number could move up?

Well, I know with the hedge that we've put in place, you know, there's about $15 million of what I call found money because, you know, we will sell that gas at $3.46. and, you know, we'll probably do -- we'll spend a little bit on capex. We'll use the majority of it to pay down our debt. But, you know, we've got those -- that set of dollars that we'll be deciding what to do with.

And, you mentioned some of the inventory, the prospects, not including the eight, can you elaborate a little bit more on what some of those prospects are and how far along you are with them?

Well, in the Gulf of Mexico, we -- last year, you'll remember we kept two or three rigs busy. And we drilled over 20 wells last year in the Gulf. This year we have 38 prospects right now in our core area, which is Ship Shoals, South Pelto, South Tim area, where we've been successful. We've kind of agreed with Bodark that we'd see where gas prices were and if we need to put a second rig out that we would consider doing that at the beginning of third quarter.

And, then onshore we've got -- well, you just take the Ball Ranch and the Ball Ranch, this second well that we drilled, the first well being a DevX well drill in July of last year and going on production in probably February this year, we drilled another well at the Ball Ranch and we've got 60-feet of pay sand there. It looks good. And, so we will now drill another well, being an exploration well in the second quarter in the Ball Ranch. But, you know, we have lots of wells we could drill there. We could go to the east. We could go to the south, or to the north of the well that we just logged. But, you know, the seismic is working in that area, the same way with the Chart Co, the well that we're drilling in CharCo is about a 16,000-foot well and we've, you know, we've, you know, will potentially will have a good well there. It's all sitting in S&J well. It's making about 10 million a day so we've got some upside there. And, South Roleta, which we operate and on a 45 percent interest we'll split that in the third quarter. So, there's a lot of places that we can spend money. I know our head of operations comes in weekly and says, you know, will you release me to spend more money. And, we'll say, well, you know, not today.

Okay great. Thank you very much.

Our next question comes from Rahem Rasheed [phonetic], from FBR. Please state your question.

Hi, Jay, a couple of quick questions just the first one on hedging. Are you guys looking at putting some more in place and the next question is in terms of project inventory looking out into `03, is Gilmer give you enough of a running room to go to this year, next year? And, lastly, reserve replacement target for this year.

On hedging, Rahem, we -- of course, you know, we typically don't hedge, as you know.

Yes.

And, we did hedge through October. We've not considered any additional hedges because 50 percent of our production is hedged. And, we think that's plenty. Particularly where gas prices are now. So, this morning, the twelve months strip went to $4.01, so it broke the $4 range. But, you know, we're comfortable where we are. And, I think if you look at where we would drill, we've not mentioned the Double A Wells field that much except for the 11 wells that we might start drilling in third quarter of this year. That would be a project that would, you know, be started the later part of this year, depending on commodity prices, but that'd take you into the first, second and third quarter of next year also, which, you know, those are your five to 7 million a day tap wells and we would own 37 percent interest.

We, you know, hopefully, we'll find an extension with a Hammond well that we're drilling right now, we own half of that or maybe 60 percent of that and Kerr-McGee's our partner. If that works and we've, you know, we have a big drilling program around the Hammond. And, we'll know that within the next -- probably the next, conservatively say the next month, maybe by the next three weeks. And, we expect some good results there.

And, Ray, I would add that, you know, we will be probably picking up, you know, back in East Texas in our other fields, the program we had last year, you know, right now we're focusing on the Gilmer and those wells. But, once that's -- once it -- feel like that's fairly developed up we'll go back and we've got several years worth of additional locations in our East Texas fields, which in a gas price environment like we're in today or, you know, they make a lot of sense. And, that's something that we'll be bringing to the budget once we kind of get through the more prolific Gilmer wells.

Yes, and, Rahem, I think if you go back and look at our approach is the board and management to development in East Texas. At the beginning of year 2000 when gas prices were lower we had no money budgeted to drill any wells in East Texas, North Louisiana because we had better places to spend our money. But, in third and fourth quarters of the year 2000 when prices went up, we drilled 18 wells and hit 17 of them in that timeframe. And, averaged about a million five a day in production. And, then you take a look at the beginning of 2001 we said gas prices were high, Litchfield wells, we drilled 19 in the first and second quarters. W e hit 19. same production, you know, about 1.5 million a day and in third and fourth quarter we said no, we're not going to drill any more there. It's -- most of that land is held by production. I think we own about a 60 percent average working interest in all the wells and we operate the majority of it, and it's a little over 405 wells. But, then when we focused on DevX we came back in this year and said, you know, that the growth in that area, being East Texas and North Louisiana will be at 21, $22 million budget similar to the year 2000 and 2001. But, it'll be in Gilmer. So, I think, like Roland said, when you come into next year, I mean we can -- we can take another look at Washcomer [phonetic] Beckville or Blocker or Longwood or Lisbon or Aida or Logansport or some of the other major fields that we operate in and we've got several years worth of inventory there.

And, in terms of inventory can this speak the same about the Bodark joint venture with some more flavor there again in terms of inventory this year next year?

Yes, with Bodark it really -- it only gets better. In our exploration program outside of the Bodark venture, as you know we've had a 67 percent success rate since 1998 and then if you look at the Bodark venture, which started in January of 1998 we've had a 67 percent success rate under that venture also. and, last year, you know, we had about an 80 percent success rate under that venture. But, when we first agreed to be in the venture with Bodark in January of `98 one man really was the major prospect generator and that's Gary Blackie with Bodark and since then they have prospect generators and that's all they do. They work and rework and reprocess the data in a core area around Ship Shoals, South Pelto, South Tim in the Gulf. And, you know, as a result of that we do have, you know, several years of inventory and that just depends on how many rigs you want to use to drill wells and that just depends upon commodity prices.

But, we picked up in March, I guess, another 25,00 acres in our core area. We've added, you know, several prospects based upon that. We're redeveloping some acreage that we bought in the Bodark acquisition in 1997, being the Ship Shoal 67, we own a half interest in that and Bodark will own a half interest in it. So, there's more work on that side and excitement going on in the shallow Gulf of Mexico right now than any other time in our corporate history. So, that looks very promising. You blend that in with Gilmer and East Texas to Belatine [phonetic] and you blend that in with hopefully some future upside in Double A. It looks pretty good.

Got you. Leverage target debt to book cap target by year-end next year and any thoughts there?

Well, our target it to get it to below 50 percent, you know, by year-end, though, it's really dependent on how strong gas prices are. And, our hope is to improve it. We're right at 63 percent.

Right.

Right now and, you know, at least by year-end we hope to get below the 60 level. A lot depends on gas prices and how much of, you know, how the profits look because of prices and how much cash flow that we use for debt repayment versus capital expenditures.

Sure. But, the upper end of the range is somewhere where you are now. You're going to want to go to.

Right. We would like -- yes, this -- we don't want to see it increase at all. We want to work it down toward are target.

No, this 62, 63 percent debt to cap I mean that's the maximum we want to be. We want to be less than that. You know, when were in the 67 to 72 percent our goal was to get to the 50's and we got to 46 or 47.

Right.

And, I think if you look at the ways we can do that, we can take some of the money from the hedge and pay down our debt quicker. I think we're going to realize a little higher prices than we thought we'd realize. So, we'll have additional cash flow there. And, then, you know, we still have hopes in Kentucky maybe the fourth quarter if prices continue to hold up and we get production to 4.5 million or so a day, which is plant capacity. That, you know, that's a real nice project for someone to buy. And, we are starting recompletions on those wells I think the 14 of this month and, you know, when we bought Kentucky it had less than a million a day and we've got it up to say 2 million a day. And, we're still working on that. So, that would be a nice divestiture that we would look at making at the right time.

Okay, perfect. Thank you.

we have Brad Davis from SWS Securities. Please state your question.

Good morning, Jay.

Good morning.

Two questions, one, Roland, if you could just talk a little bit about the legacy hedges, I guess you guys got from DevX, which was -- I'm just assuming here was the mark to market situation for the first quarter. Maybe, if you all are planning on doing something with those particular hedges, I don't know, buying them out if that's possible, or kind of your outlook there. And, then the other question was you guys, your natural gas realizations in the first quarter were a little less than what I was expecting. Are you all different in marketing or it's just this rolling in the DevX production, which is probably -- has a little more of basis or less of a basis to Henry Hub than what the company had had historically. Jay had just mentioned that he felt like that the realizations might be higher forward, can you just talk about that a little bit and that's more from a modeling perspective.

Okay. On the DevX hedges and you are correct. The DevX hedges are the hedges that were mark to marketed into income in the first quarter. And, of course, that was a result of gas prices, you know, increasing by almost a dollar between December 31 and the March 31 dates. Those derivatives that DevX had are not accounted for as hedges mainly because the largest position, which creates most of the liability is with Enron and so it's not an effective derivative. So, we've -- we're accounting for those as a non, you know, qualifying hedge derivatives. We have been, or course, through the first quarter and currently with Enron to unwind those positions. As you can imagine, it's difficult to deal with Enron because nobody has any authority. So, it's a long process that we're hoping potentially in the second quarter to unwind those, we'll either unwind them and send them our or maybe put a position, similar position in with a responsible counter party. So, it'd be our goal to unwind those. They're actually, in addition to the Enron position, there's a nice position with Texaco that is a $4 floor and $6 type cap. So, that is an asset, of course, we would probably continue to be an asset unless gas prices really move up. And, so that position will expire at the end of the year, we'll just keep that, but the large one that's causing the mark to market loss is the position with Enron.

And, then on gas price realizations I think what typically happens is I don't think there's been a big change in the realizations or the Bte content of our gas. But, when prices are low those premiums seem to really disappear. You can even look in the fourth quarter the premiums are pretty slight then because of the low prices and once we get back into prices like we had in the second, I think you'll see, you know, the similar type premiums over NIMAX. So, I don't really think that the DevX properties has changed that by much of material amount. I think it's really just the low-price setting generally that was in place for much of the quarter. Because that premium is Bte content and then what the market indexes are in the different regions.

Brad? Is there any other questions?

Yes, we have Kenneth Rothstram [phonetic] from Freeman James Online with a question. Please state your question.

Good morning, I want to generally congratulate you on a [technical difficult] basis, getting through the acquisition, picking up the DevX at a relatively low price is just on the [indiscernible] perspective adding at the right times of the cycle. I had a quick question, Roland, on those derivative contracts. The way it look to me is that they do not have a ceiling on them or do they do have a ceiling or is there an unlimited if gas were to make a run, so to speak, for over 4 one-on-one year strip, does that continue to run against us, or is there a ceiling on it? Like the Exxon has a 6.70, 6.75.

Right. The large position with Enron is a 2.40 swap, so it does not have a ceiling on it. And, the more gas prices run up the larger that liability is. Now, with that said, in our opinion, that position has been terminated by Enron and at a lower price than today's market. And, that's the position we're trying to take to go ahead and end that.

But, there's nothing there that's just -- that you don't view that what is -- you know, you don't view that as some unwieldy beast that can run away from us or anything?

No, it's like any swap, I mean, you know, obviously, when prices increase the swap becomes a bigger liability. Of course, then on the other side, you know, prices are increased. So, it is a -- you know, basically DevX had made the election to sell their gas for two years at $2.40 and you know prices have always been higher than that. That's why that's always been a liability. But, hopefully in the second quarter if our position holds up, you know, that we'll be able to extinguish that at pretty much where we marked it to market already.

Very good. And, congratulations on a macro basis. Thanks.

Thank you.

Gentlemen, at this time, we have Jeff Balt [phonetic] from Raymond James online with a question.

Could you guys maybe talk about your inventory of both Gulf of Mexico exploration projects? I noticed you guys had a pretty extensive inventory set for the second quarter. I was wondering if you guys plan to maintain that kind of pace through the rest of year and into next year?

Well, again, what we've done so far is that in like in third quarter we will keep a rig busy at Gilmer, so that's onshore, so that's three wells. And, then in the Gulf of Mexico we'll drive -- and, of course, these are subject to change. We kind of, when we move them a little bit, but will drill from a million 122, we'll drill a well at South Tim 11, then for exploration we'll drill, you know, South Roleta, Catslick [phonetic], two wells at Ball Ranch and then might be a well of what we call Seven Oaks. But, we'll drill, in the third quarter we'll drill three wells usually with a rig and this one rig being busy in the Gulf drilling wells that are 12 to 14, maybe 15,000-feet in depth. It takes about a month to do that. We use a different recompletion rig, but we would drill, you know, two to three wells and we would own anywhere from 33 percent to 40 percent.

Now, what could happen if prices, you know, we deem prices to be higher for a while, you know, we could have another rig busy. We've not elected to do that yet. But, we do have an inventory. I know we advertise 38 prospects or so, which probably, you know, in the mid-40, 45 prospects, something like that. So, we have plenty of places to drill in acreage that we've leased with prospects generated by 3D seismic that we understand that's been reprocessed several times and in areas that we've made money. So, it's not a lack of places to spend money. We want to be cautious to get our, you know, debt to cap down, only spend money from cash flow and spend it wisely.

Great. Thank you.

Gentlemen, at this time, we have no further questions.

Okay, I'd like to make maybe a closing comment. We do I think you had asked about mark to market and we've talked about that. We did have a delay in refacilitating the facility in South Tim 34 to get the production online there. We experienced that in the first quarter. That's over with now. And, I think that this exploratory well at South Tim 30, which was abandoned with 43 feet of pay sand, which was a productive well. I mean that showed up in the first quarter. That was a successful well and we had the drill pipe stock and, you know, wrote it off for $2 million and we'll probably plan to redrill that prospect pending the results with some other wells we're drilling in that area. But, you know, those were three unusual events that we reported. I think if you look at second quarter and you get the first quarter behind you I mean we've already had two very successful wells and our production is up, as Roland had said, anywhere from 8 to 10 million a day already increased. So, we are very excited about the growth of the company and we're going to be very disciplined on spending the dollars. You know, we might increase capex dollars this year because we'll have more free cash flow, but we're going to be cautious in doing that because we think that's the right thing to do.

So, with that, thank you for attending the conference call.