Callon Petroleum Co (CPE) 2008 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Callon Petroleum Company third quarter 2008 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 Tuesday, November 11, 2008. I would now like to turn the conference over to Mr. Fred Callon, Chairman and CEO. Please go ahead.

Good morning. Thank you for taking the time to call into our third quarter call. Before we begin the formal portion of the presentation this morning, I would like to ask 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 call will be considered forward-looking statements. As such, no assurances can be given that these events will occur or that the projections will be attained. Please prefer to the cautionary language included in our news release and in the risk factors described in our SEC filings. We undertake no obligation to publicly update or revise such forward-looking statements. It is also important to note that the SEC permits us in our filings with them to disclose only proved reserves that we have demonstrated by actual production or conclusive formation tests to be economically and legally produceable under existing economic and operating conditions.

During today's discussion, we may use terms like reserve potential and probable reserves that the SEC's guidelines strictly prohibit us from using in our filings with them. These estimates are by their nature more speculative than estimates of proved reserves, and accordingly are subject to a substantially greater risk of being actually realized by the Company. Finally, today we will be discussing 2008 cash flow which is considered a non-GAAP financial measure. Reconciliation and calculation schedules for the non-GAAP financial measure were stated in our third quarter 2008 results news release and can be referenced there on our website at www.callon.com for subsequent review. Fred.

Thank you, Terry. I will begin with an update on our operations and then Bob Weatherly, our CFO, will discuss our financial results for the third quarter and the nine-month period ended September 30, and then we'll conclude with guidance for the remainder of the year and follow that up with questions and answers. Let me begin with an update on, of course, our largest most important project, the development of our deepwater field in Toronto. In mid-August the Diamond Offshore rig, Ocean Victory arrived on location in Entrada. Due to our scheduled drilling of Entrada well number three during the hurricane season and the relatively close proximity to the Magnolia TLP, one of the MMS requirements was we use a 12 point boring system and vertical load anchors, VLAs, instead of the standard eight point boring system and the conventional drag anchors. We proceeded to set and test the required VLA anchors. Unfortunately the first six VL anchors failed during the test. The MMS then gave us permission to return to our original plan to use drag anchors. The removal of the VLA anchors and resetting of the drag anchors was successfully completed just as the first two hurricanes arrived.

The good news is that the conventional drag anchors did perform well during the two storms. However, we've been considerably delayed by the failed VLA anchors setting experience and two back to back hurricanes resulting in two evacuations of the drilling rig and remobilization of the crews. The Ocean Victory did come through both hurricanes with minimal damage, however our schedule was adversely affected. After drilling commenced in September, we also experienced several unrelated but frustrating mechanical operational events that have collectively delayed the drilling time for the number three well. These various events have not only increased our drilling timetable but also increased our cost estimates. As a result, the days lost due to encountering these events first production has been pushed into the second quarter of next year.

As of today the current status of our Entrada operations is as follows. We're at 18,240 feet which is our last casing point before the drilling the objective section. We plan to drill a total depth of approximately 21,100 feet. The gas and oil flow lines have been laid within 1,500 feet of the Magnolia TLP. The steel risers connecting the flow lines to the TLP are scheduled to be installed in January. All the long lead items for both wells are in hand and ready to install, and Conoco Phillips is working on the top side modifications to the Magnolia platform. Our project management team for Entrada and engineering staff are closely monitoring cost of Entrada development, estimated costs, drilling, complete both wells and the infrastructure required for subsea production to Magnolia has increased to approximately $440 million to $460 million. Although costs have increased the project economics obviously are still very good.

As you're aware our share of the development costs are being funded about $150 million loan from our joint venture partners CIECO Energy plus cash on hand and cash flows from properties as well as draws under the senior secured from credit facility with a borrowing base of $70 million. Once we get Entrada online it has the potential to double our production and cash flow. We'll then redirect our focus towards moving forward, exploring new opportunities as well as increasing our 2009 CapEx budget. Our focus will continue to be on attractive drilling opportunities as well as looking at some selective producing property acquisitions. Obviously this is the plan going forward to help us continue to place a reserve base and declining production.

Now, let me review the status of our major producing properties. While we did department sustain any significant damage to our major production facilities as a result of hurricane Gustav and Ike, the industry is still dealing with the damage of the pipeline infrastructure, the storms had a greater impact on the offshore oil and gas industry than prepares first reported. MMS estimates 19% of oil production and 29% of the gas production in the Gulf of Mexico is still shut in. As a result of these storms, we deferred production of 12.6 million cubic feet of gas a day for the third quarter. We continue to feel the impact of down time in the fourth quarter and are estimating additional deferred production of 18 million a day for the fourth quarter. Medusa is currently producing 8,000 barrels of oil, and we're flaring five million cubic feet of gas a day. The gas transmission line was damaged during the hurricanes as in the process of being repaired. The repair should be complete in the second half of November at which time Medusa should go back to approximately 15,000 barrels a day and 14 million cubic feet of gas a day. As you recall we own a 15% working interest in the Medusa field and Murphy operates.

At Habanero on we're still shut in. However, shale operators in the process of getting Habanero ready to bring back online to their Auger facility some time this week. Pre-hurricane production from Habanero field was 6200 barrels of oil and eight million cubic feet of natural gas from two wells, both producing from the Hab 52 oil reservoir, we own 11.25% interest in the number two and 25% interest in the number one well. At West Cameron 295 field we're also still shut in as a result of a damaged transmission line. The current estimate is to return this line to service in mid- to-late December. Production was a rate of 19 million cubic feet of gas and 120 barrels of oil a day from the number two and number four wells before the hurricanes. The number three well was shut in prior to the hurricanes due to sand production and a remedial workover that was not successful. Additional work is planned to return the well to production, and in addition another well may be drilled in 2009, depending on well performance, number two and four wells are operated now by Mariner, while the number three well is operated by Cimarex, and we own a 20.5% working interest in the wells.

Highland block 165 field production was resumed on October 4th, and is currently 17 million a day and 100 barrels of oil a day from the Highland 130 number two well, which produces from Gyro K-2 and Highland 130 number one well which has been recompleted to a Rob L span. We own a 16.7% working interest in Rob L and 11.7% interest in deeper sands. These wells are also operated by Mariner. We also drilled and completed our North Pronghorn prospect, first production commenced in the third quarter and the well is currently producing seven million cubic feet of gas and 165 barrels of oil a day. Apache operates and we have a 42.5% working interest in the well. While our current daily production is approximately 16 million cubic feet equivalent a day. This should of course increase significantly over the next several weeks as we bring Habanero online and Medusa back up to full production. Bob will review the results of operations for the third quarter and nine-month period ended September 30 and then following that an update on guidance.

Thank you, Fred. For the third quarter of 2008 we reported net income of $5.9 million or $0.27 per diluted share. Third quarter consensus estimate was $0.22. As Fred has already discussed, our third quarter results were significantly impacted by production down time as a result of down stream pipeline issues resulting from hurricanes Gustav and Ike. This production shortfall caused some of our derivative contracts to be deemed ineffective which resulted in derivative expense in the third quarter of $1.4 million or $0.04 per share net of tax. Included in the derivative expense was $690,000 of noncash expense. For the nine-month period ended September 30, net income was $18.6 billion or $0.85 per diluted share.

Our daily production rate for the third quarter was 25.9 million cubic feet equivalent per day. Hurricane down time resulted in daily production rate reduction of 12.6 million cubic feet equivalent per day in the third quarter. Natural gas and oil production were 1.2 billion cubic feet and 205,000 barrels respectively and were below our guidance ranges. Year-to-date natural gas production was 4.9 Bcf and oil production was 780,000 barrels for an average daily production rate of 35 million cubic feet equivalent. Oil and gas revenue for the third quarter of 2008 totaled $32.8 million. For the nine-month period ended September 30, 2008, oil and gas revenue was $125.8 million. Average realized oil prices for the third quarter of 2008 were $99.40 per barrel, a substantial improvement over $71.29 per barrel for the same quarter last year. The benchmark oil price for the third quarter measured by the average closing price of NYMEX contracts or delivery of WTI averaged $117.98 per barrel.

As discussed in previous conference calls, the spread between the benchmark oil price and our average realized oil price is due primarily to quality adjustments incurred in the sale of our oil production from Medusa and Habanero, which combined accounted for 96% of our oil production in the third quarter of 2008. Please refer to our news release for reconciliation of realized oil price for the average NYMEX price. In addition to these quality adjustments, previously established crude oil hedging positions decreased our average realized price by $18.56 per barrel for the three-month period ended September 30. Natural gas averaged $10.53 per Mcf for the third quarter of 2008. This is an increase of 32% compared to the same quarter last year. On the expense side, LOE for the third quarter of 2008 was $3.7 million or $1.55 per equivalent Mcf of production and was below the guidance range of $5.4 million to $5.9 million. G&A expense for the third quarter of 2008 was $1.5 million or $0.61 per equivalent Mcf of production. This was below our guidance from of $2.6 million to $3 million.

Interest expense was $5 million and below the guidance range of $5.3 million to $5.8 million for the third quarter. Depletion, depreciation, and amortization for the third quarter totaled $11.5 million, which was below our guidance range due to lower production volumes resulting from down time as discussed. Discretionary cash flow in the third quarter totaled $21.9 million or $0.99 per share. Discretionary cash flow is a non-GAAP measure, and in our news release we have provided a reconciliation to cash provided by operating activities. Cash flow for the quarter was used to fund capital expenditures and abandonment obligations. On September 25, 2008, we completed a $250 million amended restated senior secured credit facility led by the Union Bank of California with an initial borrowing base of $70 million, which is a $20 million increase over our previous borrowing base. The other participating bank in the credit agreement are Regions Bank and Capital One. Presently there are no outstanding draws on the line, but our current availability is $55 million due to an outstanding letter of credit of $15 million.

Following is a summary of the guidance for the full year 2008 that was provided in our news release. As previously discussed, our third quarter production was, and fourth quarter offshore production will be, impacted by pipeline issues as a result of damage due to hurricanes Gustav and Ike. As a result, for the full year we're now projecting a daily production rate of 31 million to 33 million cubic feet equivalent per day. Approximately 55% of this production will be oil. Lease operating expense should be approximately $19.5 million or $20.5 million for the full year of 2008. G&A expense should be (inaudible) to [$9.5 million] for the full year of 2008. Interest expense should range between $25.5 million to $26.5 million for the full year. With regard to DD&A we're projecting ranges of $51 million to $53 million for the full year of 2008. For the remainder of the year [825,000 million] cubic feet of gas is hedged using collars with an average ceiling price of $10.15 and an average floor of $7.68. Most of our production is sold in the general area of Henry Hub which is comparable to NYMEX.

For the year we have 135,000 barrels of oil hedged, 45,000 barrels of swaps, 90,000 barrels of collars. The average swap price is $91. With regard to the collars, the average ceiling price is $81.50, the average floor is $65. Just a reminder that realized oil prices will continue to be affected by quality adjustments and transportation costs. We anticipate transportation costs should average about $1.30 to $1.35 per barrel. Now we'd be pleased to take your questions.

(OPERATOR INSTRUCTIONS) One moment please for our first question. Our first question is from the line of Neal Dingmann with Dahlman Rose. Please proceed with your question.

Good morning, guys.

Good morning.

Say, Fred or Bob, wondering what would you consider -- I am just wondering looking forward to Entrada next year the sensitivity as far as, I know you've got a lot of things laid out at least for the initial several months for that, but was wondering how sensitive maybe the back end of next year then going forward you would be with that project based on the sort of current commodity environment?

I am not quite sure -- just to make sure I am answering your question --

As far as activity behind -- I know you laid out a lot of things and spelled out a lot, and just wondering beyond sort of the initial things that you obviously are already drilling, you've laid out a number of things, Fred, already, wondering later down the line how sensitive that you would be with that project with activity with ramping up would be to the current environment or the environment at that time?

Well, I think as we've said before, right now of course between now and the time we get first production at Entrada, we're certainly focused on our time on Entrada and getting it first production and managing our liquidity accordingly. As Entrada comes online, it is certainly our plan and continues to be our plan to ramp up our activities both in terms of drilling opportunities. We've got a number of drilling opportunities at which we are in the process of permeating and having ready, as well as looking at some acquisition opportunities, and we'll continue to do that. And quite frankly, expect obviously subject to what happens with the commodity prices next year, but certainly anticipate being in a position to ramp up activity in the second half of next year fairly significantly, both on the drilling side as well as looking at some acquisition opportunities that quite frankly given the recent events I think there may be a number of opportunities out there that may be looking even more attractive next year.

So by using almost irregardless of I guess you could say or somewhat irregardless of prices, you could still see pretty significant ramp second half of next year.

Yes, absolutely.

Okay. And then wondering on storms we've seen this year as well as what we saw in '05 what your thoughts or Bob's thoughts as far as insurance going forward.

I think the early indications we have are that the claims for Gustav and Ike will not be total size of Katrina of course, but the early indications we've had for the London market where we do place our coverage are that everybody should expect to see prices in premiums go back up again. No indication of what that means other than the underwriters apparently have some pretty significant losses this time and we expect to see another strenuous discussion in terms of our renewals next time.

Okay. And then lastly before I jump back in the queue would be just wondering now you turn everything on sort of laid out, what your G&A or your expectation of G&A would be sort of next year versus this year?

I don't see that we'll have a significant increase in G&A, depending upon what approach we take with some of the investment decisions post mid-year, but we don't see us -- we're certainly not planning on much of a rise at all in G&A.

Okay. Thanks, guys. I'll get back in queue.

(OPERATOR INSTRUCTIONS) Our next question comes from the line of James [Statco] with Morgan Keegan. Please proceed with your question.

Hey, guys, I just have a quick question. What are you forecasting your budget for for 2009 and kind of I guess funding sources also for that?

Sorry, James. What specifically are you inquiring?

Just your overall CapEx for 2009?

Sorry. Sorry. I didn't understand.

That's okay.

Obviously completing our Entrada development in 2009 is the biggest chunk that we've got right now. We've got -- as Fred said, we've got some prospects that depending upon what time of the year we get through with Entrada production, obviously commodity prices we're going to come back probably at our spring Board meeting and discuss with the Board some prospects and possible, as Fred said, looking at opportunistic possible acquisitions at that point in time, but right now we're -- we haven't firmed up exactly what our CapEx budget will be for next year.

Okay. Thank you.

(OPERATOR INSTRUCTIONS) Our next question comes from the line of Evan Templeton with Jefferies. Please proceed with your question.

Hi, guys. Just wondering if you can give a little bit more insight maybe as to how production will look in 2009, in other words, how should we look at production coming back on stream?

I think the anticipation right now is that we will exit the year in the [mid-30s] from a production rate versus kind of unfortunately what we've had here in the last little bit. Then obviously the key is two things. Entrada obviously as we get that completed and as we complete both wells, what our initial production rates will be, but as Fred has said in the past, if we drill complete these wells, find what we anticipate, finding we should see a significant increase in our daily production rates over certainly where we are now, and an increase over what our exited rates should be.

Yes. I guess what I am trying to get to is just when should most of the deferred production related to the storms, when should we expect to see the vast majority of that back online?

I think you'll see December, I think from a day rate standpoint we'll see, as Fred said, we've got Medusa, the gas lines coming which is the one that's shut down down now, the gas line should come on we think in December, Habanero is any day now, certainly in the next week, 10 days, Habanero will be back on. So that's kind of what the rate should be.

Okay. Great. Everything kind of year end.

Yes.

I guess the other question is regarding just the cash on hand over $100 million. Is that you guys looking at just kind of keep additional cash on the balance sheet, why so high?

Well, the operator of Entrada, remember we have a 50% joint interest partner, is that I I think probably about $40 million to $50 million of that total cash is in Callon Entrada, our consolidated subsidiary that's the operator of the Entrada field, and balance of it is in our basic operating company.

So that $40 million to $50 million you mention, that basically represents cash as a result of revolver drawdowns, been yet to point out the spend?

No. The cash call from our partner, and we've also booked the liabilities that for Entrada, too, so we've had both an increase in cash and increase in payables.

Got you. Fair enough. Thanks, guys.

Sure.

(OPERATOR INSTRUCTIONS) And at this time I'm showing no -- I'm sorry, we do have one more question from [Joe Lew] with [Mast] Capital. Please proceed with your question.

Good morning, guys. Just on Evan's question related to production for next year, if we were to kind of think about production returning in late fourth quarter and production for '09 ex Entrada, how should we think about the production ex Entrada for next year?

Ex Entrada?

Yes.

The legacy production which incompetent we're having exit rate of mid 30 million to 35 million, 37 million a day, obviously will continue to see a decline on that, but kind of our normal decline that we see on that production for next year, nothing dramatic.

Okay. And then also as you discussed the acquisition opportunities out there, help me understand how we should think about the -- where the direction of the Company is going in terms of acquisition targets, gas, oil, location, and funding sources?

Sure. I think the obviously the events over the last few months are I think got things -- got everyone taking a look at opportunities and we feel like that maybe from a timing standpoint as we get Entrada online, kind of second quarter next year, that we're hoping that kind of beginning third quarter that perhaps there are going to be opportunities, both obviously we've got drilling opportunities we've been working on for a number of years, and we'll continue to kind of work on our inventory there on the shelf. We also continue to evaluate and look at acquisition opportunities, certainly in the Gulf Coast region, being shelf as well as onshore. And so part of it I think is we think there is opportunities to be as I said hopefully somewhat opportunistic and be in a position to look at some acquisitions and move on some opportunities that look even better as probably over the next six to nine months.

Unfortunately with the commodity prices unless we see a significant rebound, we think there can be some opportunities that we can take advantage of with cash flow coming on from Entrada, so no traumatic change other than we will be looking both onshore, offshore, but strictly in the Gulf Coast region.

And so just want to make sure, I should think about the acquisitions more from the funding sources perspective will be largely driven by internally generated cash flows, and how should I think about the balance sheet?

Yes. I think, yes, driven by cash flow, no doubt about that. Also I think we'll obviously be continuing to watch as we all are, see where the markets are, but certainly we're not counting on at this point using any significant increase in terms of the credit markets. Fortunately we do have a credit facility in place, and with Union Bank of California where we've been working with them for years, and certainly with respect to some producing property acquisitions, we think there may be an opportunity to use that line to help with part of the funding source, and as well as looking at some possible joint venture partners on some of the projects we might undertake.

Great. Thank you.

(OPERATOR INSTRUCTIONS) Our next question comes from the line of Bruce Brown with Brown Capital Management, Inc. Please go ahead.

Fellows, in terms of hedging production from Entrada, when would you make that decision? Are you going too wait until you get first oil, or with prices apparently weakening at the present time, does that affect your timing?

I think we will wait until first oil, and whether it is literally first oil or very close to once we are very sure about the timing of first oil, we really don't -- just as a policy don't hedge production that's not online, and so once we get so that's going to be sometime out in the least the second quarter of next year. Yes, probably today's prices we probably are not looking to -- would not be looking to hedge a significant portion of that production. However, as our policy in the past, we will tend to kind of layer in hedges over a period of time, but it is going to be much closer to first production.

As far as first oil and second quarter, do you think that you're talking April or are you talking June?

I think at this point we're going to be talking more like June. It is going to be the latter part of probably the first quarter, again, depending on how things go from kind of here forward just from a timing standpoint, we're maybe being May, but I think probably April is going to be still a little early.

Alright. I appreciate that, Fred. Thank you.

(OPERATOR INSTRUCTIONS) And at this time I am showing no further pending questions. I will turn it back to you.

Once again, we do appreciate everyone taking the time to call in. As always please feel free to give any of us a call here at any time, and again we appreciate you calling in. 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 line.