Callon Petroleum Co (CPE) 2004 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the fourth quarter and year end 2004 results conference call. During the presentation all participants will be in a listen-only mode. Afterwards we will conduct a question-and-answer session. [Caller instructions.] As a reminder this conference is being recorded Thursday March 10, 2005. I would now like to turn the conference over to Mr. Fred Callon, Chairman and Chief and Executive Officer. Please go ahead, sir.

Good morning. Thank you for calling in this morning. Before we begin we'd like to start with Terry Trovato, who heads our investor relations, to make his comments.

Thank you Fred. We'd like to remind everyone that some of the comments made during this teleconference will be considered forward-looking statements within the meaning of section 2E of the Securities Exchange Act of 1934. These comments which include discussion of the Company's financial position, reserve estimates and business strategy reflect management's views as of this date. No assurances can be given that these events will occur. That the projections will be attained. There are a variety of factors that may cause actual results to differ materially from the Company's expectations. Many of these factors are identified under risk management or risk factors in Callon's annual report on form 10-K and other reports filed with the Securities and Exchange Commission. All forward-looking statements attributable to the Company are expressly qualified by these factors. Fred.

Okay. Thank you Terry. We'll begin this morning, as we usually do, with John Weatherly reviewing the fourth quarter results and year end results. And then I will kind of run through the operations review and talk about our plans for this year. And then John will follow it up with guidance numbers. John?

Thanks, Fred. For fourth quarter 2004 we reported earnings of $9.1 million or $0.45 per fully diluted share. These amounts include an income tax benefit of $6.7 million or $0.33 cents per fully diluted share. As you may remember, in the fourth quarter of last year we recorded an impairment of the carrying value of our tax loss carry forward. This impairment was required based on losses incurred over the 3 prior years, without regard of outlook for the year ahead. And as a result to the profitable operations in 2004, the impairment reserve loss reversed in the fourth quarter of 2004. Cash flow from operations before changes in working capital is a non-GAAP measure and we have included a reconciliation of this amount in our earnings release. For the fourth quarter cash flow from operations before changes in working capital totaled $14.6 million or $0.70 cents per fully diluted share.

For fiscal year 2004. we reported earnings of $21.5 million or $1.22 per fully diluted share. However, results for the year included a mix of non-recurring items. First, reinstatement of the value of the tax loss carry forward increased earnings by $6.7 million or $0.38 per fully diluted share. Costs associated with retirements in the first half of 2004 resulted in a charge against earnings of $2.9 million or $0.16 per fully diluted share. And finally, losses on the early extinguishment of debt, primarily in the first and third quarters, reduced earnings by $3 million or $0.17 per fully diluted share. So net net the non-recurring items were basically a wash and earnings were $1.22 for the year. Focusing back on the fourth quarter we produced 382,000 barrels of oil and 2.5 billion cubic feet of gas. Average daily production of 52 million cubic feet equivalent was at the center of the previously issued guidance for the quarter. Fourth quarter production was up slightly from the proceeding quarter. However, both quarters suffered equally from the effects of hurricane Ivan and the now corrected mechanical problems at Habanero. Despite the dampening effects in the second half of the year, the commencement of production from both Medusa and Habanero increased total production for 2004 by 57 percent from prior year levels. Current production levels are equal to the record rates that we set in the second quarter of 2004.

Turning quickly to cost and expenses, lease operating expenses of $4.2 million with the upper end of the guidance range. These include costs, primarily insurance deductibles, for repairs following hurricane Ivan. General and administrative expenses were $1.9 million and that was 10 percent above the guidance range. In this case we underestimated the total cost of compliance with Sarbanes Oxley Section 404. DD&A charges, accretion for future development - - I mean abandonment costs and interest expense all fell within their expected ranges. Fourth quarter earnings from recurring operations did fall short of management's estimate. And this was primarily a result of crude oil price realizations. Hedges, which are on the basis of West Texas Intermediate, reduced our average realized price in the fourth quarter by $13.88 per barrel. The hedges that had this level of impact were put in place in the first quarter of 2004 and now are in general gone.

In addition the market price for heavier blends of crude did not keep pace with West Texas Intermediate or South Louisiana Sweet. Crude from Medusa and certain other deep water filed is commingled into what is referred to as the Mars blend. In the fourth quarter of 2003 the Mars blend differential, or the discount for WTI averaged $3.16 per barrel. In the fourth quarter of 2004 this differential averaged in excess of $9 per barrel. This discount applies to our Medusa crude. But with more than 75% of our fourth quarter oil production coming from Medusa, the overall impact on prices was significant. Our overall price realization will improve in the current quarter as Medusa accounts for a smaller portion of our current oil production and the Mars differential since the beginning of the year has averaged less than $7 per barrel. It's currently $6.80 per barrel.

Year end proved reserves totaled 72.6 billion cubic feet of natural gas and 19.7 million barrels of oil or 191 billion cubic feet of natural gas equivalent. The estimated present value of these reserves, excluding income taxes, using SEC pricing guidelines for year end 2004 and discounted at 10 percent, is $613 million. Using the SEC guidelines, price realizations in this valuation averaged $6.51 per 1000 cubic feet of natural gas and $36.72 per barrel of oil. And those are net realizations recognizing basis differentials. Year end reserves include a downward revision of approximately 8 billion cubic feet. This is associated with the price sensitive roll to relief at Medusa. The 2004 year end oil pricing scenario exceeds the threshold price which triggers royalty payments to the MMS. And reserve estimates from Medusa were reduced under the assumption that such royalties will apply to all future periods. With that I'm going to turn it back over to Fred to talk about operations and then I'll come back to guidance.

Okay. Thank you, John. Let's first go through, briefly, fourth quarter drilling and development activity. First at Medusa, during the fourth quarter, we recompleted the A1 well. And production of A1 started back on January 10. With all 6 wells in operation, the field is currently producing 38,700 barrels oil and 40 billion cubic feet of gas a day. In December, at north Madusa, our Mississippi Canyon and 538 #4 well was sidetracked to reach a better portion of the T1B reservoir, in order to expose more of the pay interval to enhance the completion quality and maximize production of that well. The pay interval improved from 28 feet to 46 feet of net pay.

Operations to tie the subsea completion to the Medusa spar are in progress. With first production now targeted for early April. We expect that well to be capable of producing 5000 barrels of oil a day. The subsea equipment is configured to allow a second well to be added. We expect to re-enter and sidetrack the Mississippi Canyon 493 #1 well, which was our Stonemaker prospect this year, in order test the Northwest Medusa prospect. Which had shows in the #1 well. The reserve potential here is between 3 and 5 million barrels.

Moving to Habanero. Both the #1 and #2 wells were worked over late last year. The #2 well was successfully repaired by pulling the tubing to replace a malfunctioning safety valve. The #1 well was recompleted from the Hab 55 gas reservoir to the Hab 52 oil reservoir. Production rate, following these work-overs, is now 21600 barrels of oil a day and 35.8 million cubic feet of gas. Our third deep water field, Entrada, out at Garden Banks the 782 we continue to work on development plans there. Including drilling another well out there later this year. At Highland 119, during the fourth quarter we drilled and completed our third straight well in that field. The field is now producing 40 million cubic feet of gas a day and 680 barrels of oil from those 3 wells. We have a nonrig workover to isolate some water production in the A1 well scheduled for late March early April. After this workover we expect production from the 3 wells to be at platform capacity of 50 million cubic feet of gas a day.

In November, we drilled our North Padre Island 913 $1 well. We drilled to a total depth of 8,084 feet. The well encountered 34 feet of net pay in its primary objective and 15 feet of net pay in a secondary objective. Platform construction is underway. After which the well will be completed and tied back to an existing infrastructure of a nearby block. First production is expected in August at a rate of 15 million cubic feet of gas a day. We operate that well and we own a 50 percent working interest in North Padre Island.

Moving to our East Cam 994 prospect. The East Cameron 9 #1 well reached a total depth in January, 8500 feet. We encountered 42 feet of pay at 2 intervals. Including 34 feet of pay in the primary objective. 8 feet in the secondary objective. Platform construction is underway. And first production expected in August. We expect a rate of about 7.5 million cubic feet of gas a day. And we own 62 percent working interest and we operate that field as well.

Looking forward to 2005 as we've mentioned, our capital budget has increased by 23 percent from $65 million in 2004 to $80 million in 2005. More importantly, as we pointed out the majority of our deep water development expenditures are behind us now. And more of our budget will be directed toward new exploration and development. What we refer to as the reserve additive spending portion of our has been budget increased by 173 percent from $22 million in 2004 to $60 million in 2005. We currently anticipate drilling 4 deep water wells including 2 in the area of our Medusa fields. In addition we've identified 14 prospects elsewhere in the Gulf of Mexico region that we plan to drill.

In the deep water area we expect to drill another well at Entrada later this year. And in the Medusa area we plan to drill our Northwest Medusa prospect. We also have another prospect at South Madusa, which we expect to spud later this year. At Mississippi Canyon Block 860, the redrill of our North Bob prospect is scheduled to begin in August of this year. With the intention reaching total depth prior to the end of the year. As you may remember, the initial exploratory well was temporarily abandoned last year without reaching the objective interval after encountering drilling problems below salt. We have a 3.4 percent interest in this southern block drilling unit. Which has large reserve potential and is operated by Chevron/Texaco.

As I mentioned, in addition to the deep water area, we have 14 prospects identified so far to drill this year. We're currently drilling an exploratory well at our Pronghorn prospect on East Cameron block 2. The prospect is a structural closure with good ADO support, 3 stacked, lower Miocene [marg A] targets underneath an existing production. The prospect has reserve potential of over 200 Bcfe. The well is currently drilling, preparing to run a liner at 12500 feet with a proposed total depth of 15000 feet. And we've got a 20 percent working interest in that project. During the next few weeks, we expect to spud a well at our West Cameron 295 #2 prospect. Which has proposed total depth of 15500 feet. The well will test, [rob] MA JBO anomaly with about 32Bcf of potential. [Spendeker X] is the operator and we've got a 20 percent working interest.

Over the last year we've extended our shelf exploration program to onshore South Louisiana using basically the same exploration strategy. We expect to drill several wells in the onshore transition area this year. The first 2 prospects we plan to drill are Northwest Bayou [Mayfair Chain] and High Island. At Northwest Bayou [Mayfair Chain] in St. Martin Parish, this is a prospect with some 73Bcf of reserve potential. The initial exploratory well will be drilled 15000 feet, targeting an untested fault block immediately adjacent to the Bayou [Mayfair Chain] field which produced over 120Bcf from the same objective SAN. We own a 25 percent working interest there. And at Highland prospect in Cameron Parish, it's a lower miocene, [planaline] of prospect, 24Bcf of reserve potential. This a 4 way closure, 3 stacked objectives. 1 of which is updipped to a show. The initial well will be drilled to depth of 12000 feet. We have 30 percent working interest and we'll operate that prospect.

So in summary, we've got - - our deep water production is online for full year in 2005. We've got new production coming on line from our recent drilling successes at Highland 119, North Padre Island and East Cameron. So, we expect a nice increase in production in 2005 over 2004 based on the result - - based on the drilling we've had so far. In addition, we've got a significantly increased exploration budget. We feel like with the increased exploration activity we have, we've got an opportunity for some significant reserve increases this year. I'll now turn it back over to John to take you through guidance numbers for 2005. John?

Okay. Thanks Fred. We expect first quarter 2005 results to be significantly improved versus the 2 producing quarters. A return to record production levels will be compounded by significantly improved price realizations. A 60 percent increase in revenues to a new record level is a reasonable expectation. First quarter production is expected to increase by 35 percent from the fourth quarter of 2004. We are currently projecting first quarter production at approximately 610,000 barrels of oil and 2.9 billion cubic feet of gas. This would equate to an average of 73 million cubic feet equivalent per day and equal the production levels that we achieved in the second quarter of 2004.

Lease operating expenses are projected at approximately $5.8 million. That is an increase of approximately 10 percent from the proceeding quarter. And this increase is directly attributable to the increased production volumes and primarily at Habanero. General and administrative expenses and interest expense are expected to hold relatively flat with fourth quarter levels. DD&A charges are projected at $2.31 per Mcf equivalent. That's based on the rate calculated at year end and it's used in the fourth quarter. Total DD&A charges for the first quarter will increase directly in proportion to production.

The biggest single enhancement to first quarter earnings and cash flow will be price realizations. More specifically, crude oil price realization. The variables include not only hedges but also basis differentials and transportation cost. Focusing on the first quarter, if oil prices hold at the current level for the balance of March the average closing price for the bench mark West Texas Intermediate for the first quarter will be $50 a barrel. Based on the hedges we have in place our average price would be reduced by $4 to $46 per barrel. Based on the average Mars blend and Bonita Sour differentials, so far this year as they would apply to our Medusa and Habanero production, our average realized price, per barrel of oil, would be reduced by an additional $5.50 from the WTI benchmark to a net before transportation cost of $40.50 per barrel.

Reported sales prices are net transportation charges which average approximately $1.25 to $1.50 per barrel. The end result is a reasonable expectation for crude oil price realizations, averaging $39 per barrel during the first quarter of 2005. And this represents a full 50 percent increase from the fourth quarter levels. For the remaining 9 months of 2005 we have hedges in place providing some level of downside protection for 56 percent of our total production. These hedges limit the potential upside price for less than 30 percent of our total production.

At current NYMEX prices the natural gas hedges would have no impact on price realizations. Assuming oil prices remain at the current NYMEX levels, an average $54.80 for the next 3 quarters, hedges in place would reduce our net realizations in these 3 quarters, by $3.50 per barrel. However, this scenario would equate to a net realization of a full $5 per barrel ahead of the first quarter potential. So, with that we'll open the call up for questions.

[Caller instructions.] Our first question from Ron Mills of Johnson Rice. Please proceed with your question.

Question, Fred, for you, I guess, on the onshore South Louisiana properties. Can you walk through a little genesis of how you came away from the shelf into the marsh? And also just go back over the Cameron - - the potential of the 2 wells that you have lined up right now?

Sure. First Ron, this is really it's not a significant change, it's just an extension of the areas we're working. If you go and look at the shelf region we've been working this is really just an extension of that area. We basically just continued to move to the north of that area. So it's really just an extension of an area we've been working several years. We've been working in this area for probably over a year just continuing to prospect, explore. And so we've now identified some opportunities onshore that we plan to drill this year. Obviously costs are less than they are on the shelf. We think we've got similar reserve potential. And so it's just really an extension of the shelf program that we have been operating now for several years. The 2 prospects I talked about are Northwest, Bayou [Mayfair Chain]. We've got a 25 percent interest, 73Bcf reserve potential. Our Highland prospect has 24Bcf reserve potential and we've got a 30 percent working interest.

And you operate both of those?

We will operate High Island. We will not operate Northwest [Mayfair Chain].

Okay. And I may have missed it. The Pronghorn that you're drilling in West Cameron - - or I guess was it West or East Cameron? East Cameron, the potential out there was, can you go over that again? And then what's the potential timing in terms of reaching TD? And what kind of lead time would that have, if successful, from a production standpoint?

First off, this is a risk, exploratory prospect, big reserve potential. Over 200 Bcf in reserve potential We're at 12.5 in terms of reaching total depth. Probably 30 days, something like that we should be at total depth. If we should be successful hookup time should not be long. There is existing infrastructure with - - that the well is being drilled from. So we should be able to hook up about a matter of I would assume 90 days or 120 days, something like that.

Okay. And, John, I don't want you to get away free. With the CapEx budget you all have come out with of $80 million; first can you break that between capital expenditures and capitalized G&A and interest? and second on - - based on the guidance that you've provided looks look you'll be not only funding that intentionally but also generating some excess cash flows. And what would you all look to do with some of those excess cash flows as they come in the door?

Ron, the capital budget that we've announced for 2005 is $80 million. The spending rate is pretty even through the year. 20million per quarter plus or minus 1 million or 2. And 2.9 million per quarter for a total - - 2.9 of the 20 million each quarter is overhead and interest with that being about 1.1 million in interest and about the other 1.8 million being overhead. In terms of, I think any reasonable price scenario we certainly generate more than $80 million in cash flow for the year. We do have some capital requirements for asset retirement obligations, plug in and abandonment obligations. Actually that's pretty heavy this year, could be in the $11 million range. However, we are in the process of looking at some potential sell/salvage type operations on those fields, that frankly could maybe knock 5 million of that out. But we do have some obligations there.

I think there's some capital lease obligations that are maybe $1 million. But in any scenario I think you come to the conclusion it will still generate some cash for the year. We'll look for the opportunities on that. Of course an initial reaction would be to reduce debt. But our total debt right now is all in the form of the 7 year notes that we issued in December of '03 and March of '04. And like any high yield debt issue they have no call for half the life. So I guess there's always potential to go pick some of those up on the market. But they're trading at 106. So we may well be looking at a situation of either just accumulating some cash during the course of the year or based on opportunities we could certainly be looking at expanding our capital budget.

Okay. And Fred one more back to you. You mentioned Entrada, you hope to drill a third well out there. I guess last month in Florida you talked about BP getting to a - - hoping to get to a decision point by March or April whether to go forward with the project or farm it out or sell it. Is that time line still on schedule and what would potential development scenarios be?

The answer is yes, Ron. I think BP is moving forward with making some decision. And I expect them to make a decision here in the next couple months. So we'll - - hopefully we'll have a well drilled sometime later this year third, fourth quarter something like that. And if that's the case hopefully we'd be looking at production in early '07.

In that case is that assuming you have a stand-alone facility or you go through Magnolia?

Well, as we've said we've got 2 options there. And we continue to look at both of the options. But certainly we'll look at the option of going through Magnolia if we can work out something with them to take it through there. And certainly if that's the case that - - I think that would accelerate the time by a good 6 to 9 months.

I'll let someone else jump on. Thanks a lot guys.

Our next question comes from the line of Andy Paar of Andover. Please proceed with your question.

A couple of questions. First can you give us some more color as to the reserve reconciliation for the end of the year? You started with 217 hit the minus 8 for the revision. Produced about 22. Is there anything else in there?

No. There was - - total revisions were 12Bcf. 8 of that was the Medusa royalty issue for oil. And the other 4 was the T4 reservoir that was being produced out of the A1 well at Medusa. We had early water production there much earlier than anticipated. That well was completed uphold of the T1 reservoir . That- - T4 was the absolute smallest reservoir involved in the Medusa field. It's still a mystery of water production as to whether it was coming from the formation or not. But the decision was made to recomplete up to the more prolific A1 - - I mean T1 reservoir. And so for the time being we wrote off the balance of those reserves. That may at some point come back. But - - so there were 2 negative repeations. So the Madusa royalty 8 Bcf equivalent and the other 4 Bcf equivalent being attributed to that T4 reservoir at Medusa. And then there was about 8 Bcf in additions from the limited amount of drilling that we did get done in 2004. And then the balance, I think is 21.8 in production coming out.

Great. Secondly on the exploration program, you guys are going to step it up this year. I think you said 60 million. You cited a lot of numbers between the different wells. What do you think the total net risk to unrisk potential is there? What do you think you'd give yourself?

Totally excluding North Bob, only because it's so big. I think our risk adjusted reserve adds from our net interest in the 14 prospects that we're drilling on the shelf plus the 2 in the deep water that would really be exploratory and applying appropriate chances of success is; we're targeting close to 60Bcf of net risk reserve adds.

A couple of just housekeeping questions, what is capitalized interest in the G&A during the quarter?

During the quarter? It runs 2.9 million a quarter with 1.1 being interest and 1.8 being overhead.

Thanks, guys.

[Caller instructions.] The next question from the line of David Adams of Jeffries and Company. Please proceed with your question.

Can you give us an idea what average production was for each Medusa and Habanero during the fourth quarter? And then maybe give us an idea of what peak production will be as Medusa - - North Madusa is tied in in April?

I'm sorry. You're just asking what peak production was during each of the quarter?

No, what average production was for fourth quarter? And then when you tie in North Madusa, what do you think production will ultimately peak at?

I'm going to go to the last one first. The Madusa facility has theoretical capacity of 40,000 barrels a day plus 10,000 barrels of water a day. And it's always been an open issue, of; well how much oil could it produce to the extent it's not producing 10,000-barrels of water? And we're going to find that out the first week of April when North Madusa comes online. And that's all I can say. We are just short of 40,000 a day right now from the existing 6 wells. And to the extent it doesn't go north to 40 the wells will just be producing at constrained rates. And that will just make the decline curve much shallower. So, the answer is we don't know at Medusa where it's going to go. And you just caught me flat--footed on averaging out what Medusa and Habanero did during the third and fourth quarters because I don't have a calculator with me. And they phased in and phased out during the quarters. And where Habanero is online now is basically where it was in July of 2004 when the problem developed with subsurface control valve. Medusa had never been up to the roughly 40,000 barrels a day that it's doing now until well #6, which was the recompletion of A1 well was completed in late December. So it's certainly - - Medusa just on a general basis; the rate's now is Habanero is as good as it ever was and Madusa is more than it was.

Okay. That's all I had.

Our next question from the line of Greg [Embrues of Pallick Investments]. Please proceed with your question.

Could you break out proved reserves in terms of Entrada both in B's as well as PD10? I think it was in the 70's last year? Fall under undeveloped?

Give me just a second Greg.

And then as you're looking if you could break out the puds also, total puds.

Entrada is - - what about this way - - Entrada is 75.8 B's net. PD10 of 219 million. And to be honest that is the bulk of our undeveloped reserves.

What are they in total?

I'm working on it here. Puds are 38.6Bcf and 9.45 million-barrels.

Okay. So about 95 total. And could you go through I know you've gone through this previously but in terms of your CapEx between development exploration?

I would total 80 million, Greg. First you have the - - I guess roughly 11.5 is capitalized overhead and interest which you can call whatever you want.

Right.

5 to 5.7 million for Medusa and Entrada. Both of which you have to characterize as development. 2.5 million for North Medusa which you'd classify as development. I'm looking for any other developments involved.

And what's the total 65?

Total CapEx is 80.

80, including the capitalized.

Including that and including a very aggressive roughly 17 million on leases and sizing.

Does that include the P&A?

No. Not since they started making us break it out in separate balance sheet items. And then as far as development, we have the North Padre Island discovery that there's 4 million in this year's expenditures to get that one online. And there's also about in into East Cameron 90 to - - but that's for this year's drill.

Okay. And If we exclude Entrada, well where do you expect to be at year end - - what's your target for year end reserves? What are your expectations?

Well, I would certainly hope that we would in fact add the 60Bcf, our risk adjusted drilling target. And then we'll produce whatever the 27.

So you'll have about 30 net adds?

33 AF. Roughly 200 percent production plus.

Okay. And have you done additional hedging?

No.

Do you expect to in the next?

No, Greg. Things are extremely different. I mean the bulk of the hedges we have in place and I know you've followed us long enough to remember the situation, those were put in place in the first quarter of '04. At a point in time where we still had $60 million of near term debt maturities and a very real need to start making firm commitments to a capital budget to replace production. And to charge on its 2004, having to face 60 million of debt maturities and fund a capital budget under the hoax that prices would stay up was totally irresponsible. And we had no choice but to hedge some portion of our production. We picked lower levels for the collars that would preserve the level of cash flow we needed to address those 2 items and based on the market at that time we got the feeling we could get. I wouldn't second guess that. I would do the same thing in the same circumstance, if it came up. If we were in the same circumstance.

But things are totally different. We didn't envision we would be able to add on 15 million to our 7 year note offering. That we would raise $45 million in equity. That we would be able to through those 2 sources address the 60 million in near term debt maturities. And we have now a liquidity where we can certainly take some price risks in terms of our production going forward. But as I mentioned we have, we do have downside protection on 57 percent of our production for the balance of the year. And if you look at it the things that have been done most recently are purchase some cheap floors. Which is really insurance against a collapse in price.

Oh, sure. I wasn't questioning the hedges.

We haven't added anything recently.

I was wondering about more specifically '06, with the strong levels.

Looking at '06 we've discussed it. To be honest, those options, there's a lot of volatility in those options. And floors at $15 below the current market still have unreasonable some kind of premiums on it. So I would say that if based on recent discussions if anything if we have additional some strength in the market if we were to do any additional hedging it would probably just to be to lock in $55 oil prices.

Fair enough. And are you - - what are the LC's outstanding if any?

We have a couple of letters of credit out to counter parties on the hedges but I don't think that's more than about $2.5 million.

Okay.

Next question from the line of Chris Potter of AG Edwards. Please proceed with your question.

Good morning gentlemen. I don't want to take up too much time. Fred, can you give me a quick summery of the 2004 drilling program in terms of the successful wells both kind of on the shelf and the deep water?

Sure. As we've mentioned 2004 we a little bit talked earlier, we still have a majority of our expenditures going for development. In 2004 we drilled in the deep water area. Of course we drilled North Bob but that was temporarily abandoned. We drilled at South Medusa. We drilled a well there that was dry. And then on North Madusa we did the sidetrack which we talked about earlier. On the shelf we drilled Mobil 955 in our shallow gas area. We drilled a successful well there at 955 #3. We drilled at West Cameron 36. We had 3 dry holes on the shelf at West Cameron, West Cameron, East Cameron. Then we drilled 3 successful wells at Highland 119. And then we drilled North Padre Island 913. And then I guess East Cameron, that was early set this year, January this year. So that's it.

Okay. And so you're definitely obviously stepping up that effort in here '05. Are you going to be active in the March lease sale do you think?

Not very active but we certainly will be there and we'll certainly be bidding. And so Yes, we are actively generating and working up prospects.

Okay. 1 or 2 quick - - basically it looks like you're pretty much looking for - - based on your first quarter and full year guidance, you're sort of looking at a kind of flat type profile for '05? Is that fair?

That's fair. These are, all of these reservoirs are going to decline. And we so we're peaking out at the rate maybe when Highland 119 gets on at the end of the quarter and you'd be facing natural declines. However, you'll have North Madusa coming in which might stabilize the decline at Madusa a little bit. And then later in the year, probably August time fram, you'll have North Padre Island 913 and East Cameron 90 coming on. Which will at least offset some of the declines on the other field. So you have knowns coming in to the production stream that will at least stabilize production through the year. And with a exploration program as active as the one we have we would certainly hope to be adding some things to that.

Well, that was my question. So, there's very little exploration wedge if any in your?

The only in there are the knowns that I mentioned.

Right. No exploration wedge.

Very good. And finally, John, could you give me the NYMEX reference prices for your year end PD10?

The NYMEX reference price. No. I don't have it with me. No. That's the net realization. And the PD10 is $36.72 a barrel but that is net of the Bonita Sour and Mars blend differentials.

So about what $5?

Yes, thats probably reasonable. Yes. Very volatile. It was $9 average for just the Mars blend in the fourth quarter. And that applies to roughly 60% of production so probably 5.50 overall just for that. But I think Mars ended up the year certainly less than 9. It's bounced from 5.50 to 13 during the last 6 months. Fortunately it's 6.80 today. And a little less than that average year to date.

Okay. That hurt a lot of other companies. Thank you, guys.

We have a followup question from the line of Ron Mills of Johnson Rice. Please proceed with your question.

Just to follow up on Andy's reserve question. Were you able in terms of 8 Bcf of reserve adds, can you walk through where some of those adds were, in terms of was it North Padre Island? Were you able to get anything booked at East Cam 90? Just looking for source of adds.

No. East Cam 90 was not drilled first quarter. So certainly there's nothing in there for it. The bulk of it, and I think it's probably kind of an equal split would be between Highland 119 and North Padre Island 913. There is an anemic amount of reserve adds in there for North Medusa in 2004. If you remember where we stood at year end is we had drilled North Madusa, drilled for structural advantage so it had penetrated the thin sand at the crest of the reservoir. And in accordance with FCC guidelines you can only book based on that demonstrated sand thickness down to lowest known oil. So it was a very small amount. With the sidetrack we had in the first quarter of 2005, we not only demonstrated a thicker reservoir but we substantially lowest known oil so you'll be seeing an upward revision to reserves at North Medusa in the first quarter as a result of that sidetrack. Back to answer your question, the 8 Bcf adds is pretty much - - is kind of an even split between North Padre Island and Highland 119.

We have a follow-up question from the line of Andy Paar of Andover. Please proceed with your question.

Can you just refresh my memory on the royalty threshold for the Medusa in the revision? Is there a quick answer to that?

The - - it's independent for both oil and gas. And in 2003 we were already past the gas threshold. So it's got to be down in the 450 ranges. And of course year end numbers for 2003 already had the assumption that royalties would come out in the future on gas. On the oil I'm thinking Andy, that it's around 37.50. But remember that is an awkward application on that thing. It is done strictly on an annual basis. And you don't know the answer until December 31 of each year. Because it is based on the average daily closing price of the prompt month contracts. So it's - - the way it works is we'll pay royalties monthly going forward into '05. If it drops below 37.50 or whatever we would quit. Or if it ends up there at the end of the year we would ask for a refund. But I don't think we'll be asking for a refund.

That's it. Thanks.

Mr. Callon, there are no further questions at this time. I will turn the conference back to you, sir.

Okay. Once again, we appreciate everyone taking the time to call in. If you have any questions in the meantime don't hesitate to give me a call or John at any time. Thanks so much.

Ladies and gentlemen, that does conclude our conference call for today. We thank you for your participation and ask that you please disconnect your lines.