Callon Petroleum Co (CPE) 2003 Q3 法說會逐字稿

Ladies and gentlemen thank you for standing by and welcome to the Callon Petroleum Company third-quarter 2003 results conference call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question-and-answer session. (OPERATOR INSTRUCTIONS).

As a reminder, this conference is being recorded Wednesday, November 12, 2003. Your speakers for today are Mr. Fred Callon, President and Chief Executive Officer, and Mr. John Weatherly, Senior Vice President and Chief Financial Officer.

I would now like to turn the conference over to Mr. Fred Callon. Please go ahead, sir.

Thank you for taking time to join us again this morning for our third-quarter conference call.

As always, we would like to begin with Terry Trovato, who heads our Investor Relations, to make a few comments.

Thank you, Fred. We would like to remind everyone that some of the comments made during this teleconference will be considered forward-looking statements within the meaning of Section 21-E 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 or that the projections will be attained.

There are a variety of factors that may cause the 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?

Thank you, Terry. Again, we appreciate your joining us this morning. We will begin with a review of our third-quarter financial results by John Weatherly.

For the third quarter of 2003, we reported a net loss of $2 million, or 17 cents per common share; this is both basic and diluted. Third-quarter production averaged 33.3 million cubic feet of natural gas equivalent per day. This was 12 percent below second-quarter levels and 10 percent below the middle of our guidance range for the third quarter.

Third-quarter production shortfall is attributed in total to compressor problems in the Mobile Block 952 955 facility, so approximately 50 percent of our total gas production passes through these compressors. During the third quarter, Compressor A experienced 15 percent downtime and Compressor B experienced 58 percent downtime. As a result, third-quarter production was 832 million cubic feet below potential. This average is little more than 9 million cubic feet per day when spread over the entire quarter.

We were aware of some of these compressor problems in early August and actually factored about half of the shortfall into our guidance numbers. We did not anticipate the September problems, which is why we were 5 million cubic feet per day under our guidance range.

On a positive note, through the first six weeks of this quarter, runtime has averaged 95 percent for both of these compressors.

Gas prices for the third quarter averaged $4.97 per thousand cubic feet; this is 11 cents per Mcf below Henry Hub prices for the quarter as result of pagers, primarily applicable to July production.

Operating expenses for the third quarter totaled $2.7 million. This was the low end of our guidance range and about 6 percent below the same quarter of last year. The decline versus the same quarter last year resulted from the sale of two marginal fields which, of course, are not included in this year's numbers.

G&A expenses were down from the average incurred during the first half of the year and were below our guidance range. Current quarter G&A expense was almost flat -- or was flat -- with the third quarter of last year.

Then finally, interest expense for the quarter totaled $7.5 million; this was equal to the low end of our guidance range. Total debt during the third quarter increased by $2 million, and this increase was slightly less than what we had factored into our guidance numbers.

So I will turn it back to Fred to discuss current operations and then I'll talk about guidance a little later.

Thank you, John. On the operations side, during the third quarter, the drilling equipment was installed on a platform at our Medusa field. The risers have not been installed on the A-1, A-2 and A-3 wells, and we're currently completing the A-1 well. First production is expected within the next week to ten days. As we discussed before, we anticipate completing a well a month and that should take us reaching peak production by March.

Then at Habanero, you know, our two wells have been completed as take points for our Hobb (ph) 52 oil sand and our Hobb (ph) 55 gas with modifications to the auger platform have been completed (sic) and the Derrick barge DB 50 is in the field laying flow lines to the auger platform. We estimate first production in early December. Initial production rates are expected to be some 25,000 barrels a day and 70 million cubic feet of gas per day.

On September 20th, we began drilling our North Bob Prospect located out in Mississippi Canyon Block 815 816 area. As you will recall, we own a 3.3 percent increase in a seven-block drilling unit operated by Chevron-Texaco. This is an exploratory prospect with large reserve potential in excess of 400 million barrels. We expect to be at total depth before year-end.

That's the operations update right now. For now, I'm going to turn it back to John and let him talk a little bit about guidance. John?

Okay, looking strictly at the fourth quarter, with respect to the guidance for the fourth quarter, I'm going to break this down into three pieces -- first, existing properties; second, Medusa; and third at Habanero. We are projecting production from our existing properties to remain flat with the third-quarter level of 33 million cubic feet equivalent per day, and that will consist of 91 percent natural gas. Better runtimes at the Mobile area compressors will be offset to some extent by normal decline rates.

Operating costs for the existing properties should remain at approximately 85 cents per Mcf equivalent. Likewise, G&A expenses are expected to remain at approximately $1.1 million per quarter, regardless of production levels.

We expect to see incremental production from Medusa begin in approximately ten days with one well online, a second well is forecasted to come online 30 days later. The production from these two wells in the second half of the fourth quarter should add between 8.5 and 9 million cubic feet equivalent per day to the fourth-quarter average.

Incremental operating costs from Medusa will include fixed operating costs, transportation fees and production handling fees. These will breakdown into fixed and variable pieces. The fixed portion should run about $128,000 per month net to Callon's interest. Variable costs would total 95 cents per thousand cubic feet equivalent. These variable costs do include anticipated throughput fees associated with our previously announced transfer of partial ownership in the spar.

We expect to see incremental production from Habanero beginning in the latter half of December. Production from two wells -- even though it may only be for two weeks -- should add between 1.5 and 2 million cubic feet equivalent per day to the fourth-quarter average.

Incremental operating costs for Habanero will include fixed monthly fees, transportation fees and production handling fees. These will also break down into fixed and variable pieces. The fixed portion should run about $36,000 per month net to Callon's interest. Variable cost would total 75 cents per thousand cubic feet equivalent, and these variable costs do include the use of Shell's auger facility.

Pulling this all together, assuming the start-up dates I cited for both Medusa and Habanero, fourth-quarter production should average between 44 and 46 million cubic feet equivalent per day. This would be 30 percent ahead of third-quarter levels and would still consist of approximately 75 percent natural gas.

I mentioned the fixed and variable elements of the operating costs for one specific reason. If you look at the guidance numbers for the fourth quarter, you will see what appears to be a substantial increase in estimated operating costs per Mcf equivalent. This is the cost of the fixed cost elements at both Habanero and Medusa being spread in the initial months of production over relatively small production volumes from those two fields. As those fields reach their full production rates in the first quarter of next year, you will see operating costs pull back to a more reasonable level on a per Mcf equivalent basis.

We have very little outstanding in terms of hedges. For December through March, we have collars covering 3 million cubic feet of gas per day, about 10 percent of our current gas production levels. This collar has the floor of $5.25 per Mcf and a ceiling of $7.25 per Mcf.

So with that, we will open the call up for questions.

Thank you. (OPERATOR INSTRUCTIONS). Scott Brown (ph) from Johnson Rice.

Mr. Brown, your line is open and interactive. Please go ahead with your question. One moment pleased as I verify that line.

There appears to be no answer from Mr. Brown's line, so I will turn the call back to because I'm not showing any further questions. Oh, one just came up and it's from the line of David Hackenan (ph) from Hibernia.

This is David. I just wanted to ask a quick question on Medusa. Expected well rates per well -- you're giving first production at 7 to 10 days, and then 30 days following that. Is it three or four wells that will come online at Medusa?

Wells in total and each of the wells (indiscernible) individual in expected production rates.

But you had installed three risers I guess already, so you would have three wells and then you would install risers was the question.

That's right. We decided to match the first three and then -- (Multiple Speakers) -- the second three.

Then the expected rates per well?

It may vary substantially, David.

Are you bringing on gas wells first and then oil wells -- (multiple speakers)?

No, they're all going to be oil wells with associated gas. I believe first completion is in the T4 (ph) reservoirs, which should be a -- is potential (indiscernible) 10,000 barrels per day well. The second one is probably less than that, maybe even half of that, but like Fred said, there's going to be a substantial -- some differences in the rates on the individual wells but the first one is a pretty strong one.

Okay, so from a schedule of a ramp up, you'd bring on the three wells then you'd have another batch set of roughly what -- a 30 or 45 day time to set the other three risers and then you'd go into another three wells in, like, second quarter of 2004 timeframe?

That's right. About 30 days to completing (indiscernible) well with a pause for about 30 days to set the three risers in between, but current projections are we are not going to necessarily need to all six wells on before you start reaching maximum.

Yes, and the peak capacity of the facility 110 million a day and 40,000 barrels of oil a day?

40,000 barrels of oil. There will probably only be around 38 to 40 million a day of associated gas -- (Multiple Speakers).

Okay. Then Habanero, from an expected rate standpoint, late December start-up -- what's your confidence of actually getting fourth-quarter production there? What's your weather delay, window for getting the full lines in and commissioned? I'm just trying to get a little feel for that.

The delay at Habanero -- everything has gone extremely well with Habanero. The delay was a delay in the arrival of a lay barge (inaudible) hung up in loop currents on a job at Devil's Tower. It arrived ten weeks late. That was the total reason for the slide. Since it has been there, the flowline lake has gone extremely well and is running ahead of schedule. So, I think we're pretty confident we will see production from Habanero during the month of December. As opposed to Medusa, the ramp-up time for production rates at Habanero is relatively short, such as two weeks.

That was all I had. Thanks a lot.

(OPERATOR INSTRUCTIONS). Our next question is from the line of Ben Atkinson from (indiscernible) Securities.

My question is on hedging. What additional hedging, if any, do you plan on doing going into the new year and generally, over the next year or so?

We certainly intend to hedge. As of as a matter of policy, we have never hedged a production stream before that production stream is online, so in terms of looking specifically at crude oil hedges, we will, in all likelihood, wait until around year-end before we do any hedging on crude.

On natural gas, we will continue to watch that and certainly intend to hedge, more frankly, the one hedge we have on. We had three transactions teamed up to go that day and the spike that particular day was so short that we only got one of the transactions done. We are certainly looking to do some more in gas. We have historically hedged in anywhere from the 40 to 60 percent range, and that's always been gas.

Crude -- we will be hedging crude (indiscernible) across the end of year. The difference there will be an issue of what term. It's extremely hard to hedge crude, given the backwardation and the current curve, so it may be more of an issue of how far out we go in terms of crude hedge.

Could I jump on and ask one more question with Ben? You're obviously going to have a substantial build-up in cash flow in '04. What's the thought process on paying down the debt and how you're going to make all your various covenants?

We certainly do have a build-up in cash flow. We certainly have some relatively substantial debt maturities -- 22.9 million of subnotes due in July, 40 million of subnotes due in September. So, it is a process. We are going through the various alternatives on how to balance the cash flow, address those maturities and yet recognize the need for some discretionary spending to replace production and even increase reserves. I think it points to some combination of using the discretionary cash flow we will generate next year, together with some level of refinancing financing, in order to address both the current maturities as well as the '05 maturities and capital spending needs. But the pure intention is the net result of that will be some level of deleveraging during the course of next year.

Okay. On the refinancing part, can you give us any idea as what your plans might be?

I can give you an idea of what my preference would be, given the current markets -- would be to be in the high yield market right now in terms of the level of debt I would like to -- on a long-term basis -- fix. Because that market, as I understand, is hot and we have seen some single (indiscernible) E&P deals priced at what I consider some very attractive rates over the last four to five months. That's going to be strictly a question of -- I will be there as soon as I can get my rate, and the rating is going to be dependent on getting Habanero and Medusa on line and having some level of sustained production so that we can get pro forma credit for that in our credit stats and coverage ratios. But that's something we will be, I think, actively pursuing during the first quarter.

So Fred, it sounds like year-end audit numbers, production numbers and then see if you've got a story that can lock in some long maturity debt to get this short-term stuff out of the way.

That's correct -- a good addition to adopting a policy (indiscernible) using some portion of cash flow to pay down debt.

Right. Do you think you'll still have a little cushion left over to be putting into new opportunities?

Absolute, absolutely. We obviously have a lot of drilling plans, both in the deep water and a very active shelf program to put together, and we certainly plan to kick off additional drilling as cash flow picks up in the first and second quarters of next year.

John Stables from Morgan Keegan.

Good morning, guys. I just want to make sure I'm doing the math on this right first. I see, from what you said earlier, that 33 million from your existing in-production, Habanero would contribute another 1.5 to 2, and so I guess Medusa would be another 10 or so?

I think I quoted 9.5 to 10, yes.

9.5 to 10, all right. Some of this may be a little premature, but I want to get an idea of sort of shaping our expectations for next year a little bit. Based on bringing up a well a month and the expected production of those wells, what would you ballpark sort of the exit rate at Q1 to be at this point?

This gets difficult because we haven't given guidance for next year and don't intend to until approximately the middle of next month when we're pretty sure about the start dates and ramp-up rates.

However, we have stated, on a couple of occasions, as a good indicator is we expect the exit rate for next year -- first quarter of next year -- to be approximately double this year's average daily production rate.

Okay. I guess in addition to that next-year question, also, you said there would be a pull-back on some of the expenses. How far do you think that will come back?

Now, total expenses aren't going to. What we will do is the per Mcf equivalent will come down, but as those fixed costs at Medusa and Habanero are ultimately spread over the potential average daily production as opposed to a relatively low initial daily production rate.

Okay. All right, I think that's all I had.

Chris Picolle (ph) from A.G. Edwards.

Good morning, John and Fred. This is Greg. (LAUGHTER). Well, I've gotten younger here in the last week! We got on a little late, Fred. I apologize. Did you give us an update on the timing of the deep water production? If you didn't, could you do that?

Yes, yes -- (technical difficulty) -- at Medusa, we are looking at first production, you know, a week to ten days -- you know, and we're looking at Habanero; we now think the first week of December. It's just some detail, operational things, no one thing that's holding it up, but that's a rough timeframe at this point.

Okay. In terms of your expected ramp to, I guess, what we would view as maximum production levels, given the current number of wellbores, when would we get there? Is that second quarter, third quarter?

At the end of the first quarter, maybe early in the second but right now, we're targeting the end of the first quarter.

John, you indicated -- I know you haven't given guidance for '04 yet, and it's certainly premature probably to do that, but you indicated that your expectation would be that '04 production would be in the neighborhood of double '03. Is that correct?

I was speaking as to an exit rate for like -- the first quarter next year it would be there. Of course, Medusa is not going to go off-peak immediately. There's going to be -- you know, the wells are going to be choked back a little bit because, in the aggregate, they should be capable of doing better than 40,000 barrels per day. Ultimately, a decline will start but then again, we have to we have -- (technical difficulty) -- Medusa, which possibly will be ready to tie in to Medusa at the beginning of, say, the third quarter of next year, and help keep that production rate flat. It's possible that, based on the results and drilling in the first quarter, that may end up to be South Medusa, but certainly, we see the opportunity to keep it roughly flat at that rate.

Okay. In terms of securing a rating for some long-term -- when would you go out and attempt to do that? What is your expectations in terms of the coupons?

Greg, the coupon rates -- you know, looking at B deals done recently for Gulf Coast E&P companies, I know there was one done in the summer at probably a record rate of 7.25. I think one done more recently was in the 8.75 rate range. I think that that market is probably still about there. I think we have a shot at (indiscernible).

Sub-9?

Yes, nine, possibly less.

To get that, are you going to need to have everything off production before you get that rating, or is that something you can work on early?

I think we can start working early. I don't think we're going to go to a rating agency before we have them online. Maybe not Medusa at peak; probably not Medusa at peak but certainly we (inaudible) the two deep water discoveries online.

Thanks very much, guys.

I'm showing no further questions at this time. I will turn the conference call back to you for your closing comments or to continue with your presentation.

Once again, we thank everyone for taking time to call in. As usual, if you have any questions, please don't hesitate to give John or me a call in the meantime. Thank you.

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